SOUTHERN CALIFORNIA EDISON COMPANY
[LOGO]










2001 ANNUAL REPORT
















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Southern California Edison Company








Southern California Edison Company (SCE) is one of the nation's largest investor-owned electric utilities.
Headquartered in Rosemead, California, SCE is a subsidiary of Edison International.

SCE, a 116-year-old electric utility, serves a 50,000-square-mile area of central, coastal and southern
California.



       Contents
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 1     Selected Financial and Operating Data:  1997 - 2001
 2     Management's Discussion and Analysis of
       Results of Operations and Financial Condition
21     Consolidated Financial Statements
26     Notes to Consolidated Financial Statements
49     Quarterly Financial Data
50     Responsibility for Financial Reporting
51     Report of Independent Public Accountants
52     Board of Directors
52     Management Team






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Selected Financial and Operating Data:  1997 - 2001                                 Southern California Edison Company

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Dollars in millions                                       2001        2000         1999         1998         1997
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Income statement data:

Operating revenue                                       $ 8,126     $ 7,870      $ 7,548      $ 7,500       $ 7,953
Operating expenses                                        3,509      10,529        6,242        6,136         6,311
Fuel and purchased power expenses                         3,982       4,882        3,405        3,586         3,735
Income tax (benefit)                                      1,658      (1,022)         438          442           520
Provisions for regulatory adjustment clauses - net       (3,028)      2,301         (763)        (473)         (411)
Interest expense - net of amounts capitalized               785         572          483          485           444
Net income (loss)                                         2,408      (2,028)         509          515           606
Net income (loss) available for common stock              2,386      (2,050)         484          490           576
Ratio of earnings to fixed charges                         6.15       (4.28)        2.94         2.95         3.49

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Balance sheet data:

Assets                                                 $ 22,453    $ 15,966     $ 17,657     $ 16,947      $ 18,059
Gross utility plant                                      15,982      15,653       14,852       14,150        21,483
Accumulated provision for depreciation
 and decommissioning                                      7,969       7,834        7,520        6,896        10,544
Short-term debt                                           2,127       1,451          796          470           322
Common shareholder's equity                               3,146         780        3,133        3,335         3,958
Preferred stock:
  Not subject to mandatory redemption                       129         129          129          129           184
  Subject to mandatory redemption                           151         256          256          256           275
Long-term debt                                            4,739       5,631        5,137        5,447         6,145
Capital structure:
  Common shareholder's equity                            38.5%       11.5%        36.2%        36.4%        37.5%
  Preferred stock:
   Not subject to mandatory redemption                    1.6%        1.9%         1.5%         1.4%         1.7%
   Subject to mandatory redemption                        1.9%        3.8%         2.9%         2.8%         2.6%
  Long-term debt                                         58.0%       82.8%        59.4%        59.4%        58.2%

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Operating data:

Peak demand in megawatts (MW)                            17,890      19,757       19,122       19,935        19,118
Generation capacity at peak (MW)                          9,802       9,886       10,431       10,546        21,511
Kilowatt-hour deliveries (in millions)                   78,524      84,430       78,602       76,595        77,234
Total energy requirement (kWh) (in millions)             83,496      82,503       78,752       80,289        86,849
Energy mix:
  Thermal                                                32.5%       36.0%        35.5%        38.8%        44.6%
  Hydro                                                   3.6%        5.4%         5.6%         7.4%         6.5%
  Purchased power and other sources                      63.9%       58.6%        58.9%        53.8%        48.9%
Customers (in millions)                                    4.47        4.42         4.36         4.27         4.25
Full-time employees                                      11,663      12,593       13,040       13,177        12,642




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Management's Discussion and Analysis of Results of Operations and Financial Condition

The following discussion contains forward-looking statements.  These statements are based on Southern California
Edison's (SCE) current expectations about future events, based on knowledge of present facts and assumptions
about future developments.  These forward-looking statements are subject to risks and uncertainties that could
cause actual future activities and results of operations to be materially different from those set forth in this
discussion.  Important factors that could cause actual results to differ include risks discussed in the Market
Risk Exposures and Forward-Looking Statements sections.

Until early 2002, SCE faced a crisis resulting from deregulation of the generation side of the electric utility
industry through legislation enacted by the California Legislature and decisions issued by the California Public
Utilities Commission (CPUC).  Under the legislation and CPUC decisions, prices for wholesale purchases of
electricity from power suppliers are set by markets while the retail prices paid by utility customers for
electricity delivered to them remained frozen at June 1996 levels except for the 10% residential rate reduction
starting in 1998 and the 4 cents-per-kWh surcharge effective in 2001.  See further discussion of the CPUC rate
increases in Rate Stabilization Proceedings.  Beginning in May 2000, SCE's costs to obtain power (at wholesale
electricity prices) for resale to its customers substantially exceeded revenue from frozen rates.  The shortfall
was accumulated in the transition revenue account (TRA), a CPUC-authorized regulatory asset.  As a result of a
March 27, 2001, CPUC decision, the TRA balance was transferred retroactively to the transition cost balancing
account (TCBA).  The TCBA was a regulatory balancing account that tracked the recovery of generation-related
transition costs, including stranded investments.  SCE has borrowed significant amounts of money to finance its
electricity purchases.  Uncertainty regarding SCE's ability to recover funds spent to purchase power created a
severe liquidity crisis at SCE.  However, based on the settlement agreement with the CPUC (discussed below)
permitting full recovery of past power procurement costs, SCE was able to arrange new financing and together with
cash on hand, was able to repay its undisputed past-due obligations in March 2002.

In October 2001, a federal district court in California entered a stipulated judgment approving an agreement
between the CPUC and SCE to settle a lawsuit.  On January 23, 2002, the CPUC adopted a resolution approving the
establishment of the procurement-related obligations account (PROACT).  See discussion below.  SCE believes that
the settlement agreement will enable SCE to recover its previously undercollected power procurement costs.  In
compliance with the terms of the settlement agreement and the CPUC resolution, in the fourth quarter of 2001, SCE
established a $3.6 billion regulatory asset for these previously incurred procurement costs, called the PROACT.
A corresponding credit to earnings was recorded, in connection with this regulatory asset, in the amount of $3.6
billion ($2.1 billion after tax).

On September 1, 2001, SCE began applying to the PROACT the difference between SCE's revenue from retail electric
rates and the costs that SCE is authorized by the CPUC to recover in retail electric rates.  The settlement also
calls for the end of the TCBA mechanism as of August 31, 2001, and continuation of the rate freeze until the
earlier of December 31, 2003, or the date that SCE recovers the PROACT balance.  If SCE has not recovered the
entire PROACT balance by the end of 2003, the remaining balance will be amortized in retail rates for up to an
additional two years.  For further details on the settlement with the CPUC and the CPUC resolution, see CPUC
Litigation Settlement Agreement and PROACT Regulatory Asset discussions.

Accounting principles generally accepted in the United States permit SCE to defer costs and record regulatory
assets if those costs are determined to be probable of recovery in future rates.  SCE assessed the probability of
recovery of the undercollected costs that were previously recorded in the TCBA in light of the CPUC's March 27,
2001, and April 3, 2001, decisions, including the retroactive transfer of balances from SCE's TRA to its TCBA and
related changes that are discussed in more detail in Rate Stabilization Proceedings.  These decisions and other
regulatory and legislative actions did not meet SCE's prior expectation that the CPUC would provide adequate cost
recovery mechanisms.  As a result, SCE's financial results for the year ended December 31, 2000, included an
after-tax charge of approximately $2.5 billion ($4.2 billion pre-tax), reflecting a write-off of the TCBA and net
regulatory assets to be recovered through the TCBA mechanism, as of December 31, 2000.  Transition costs in
excess of transition revenue were also incurred during 2001, resulting in additional net charges against earnings
of $328 million ($552 million pre-tax) through August 31, 2001 (the effective date of the PROACT mechanism).


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                                                                                Southern California Edison Company




The following pages include a discussion of the history of the TRA and TCBA and related circumstances, the
significantly negative effect on the financial condition of SCE of undercollections recorded in the TRA and TCBA,
the current status of the undercollections, the impact of the CPUC's March 27, 2001, decisions and related
matters, and the implementation of the CPUC settlement agreement and the PROACT mechanism, and SCE's March 2002
financing.

Results of Operations

Earnings

In 2001, SCE earned $2.4 billion, compared with a loss of $2.1 billion in 2000 and earnings of $484 million in
1999.  SCE's 2001 earnings included a $2.1 billion (after tax) benefit resulting from the reestablishment of
procurement-related regulatory assets and liabilities as a result of the PROACT resolution and recovery of
$178 million (after tax) of previously written off generation-related regulatory assets, partially offset by $328
million (after tax) of net undercollected transition costs incurred between January and August 2001.  SCE's loss
in 2000 included a $2.5 billion (after tax) write-off of regulatory assets and liabilities as of December 31,
2000.  SCE's 1999 earnings included a $15 million one-time tax benefit due to an Internal Revenue Service
ruling.  Excluding the $2.0 billion net benefit in 2001, the $2.5 billion (after tax) write-off in 2000 and the
$15 million benefit in 1999, SCE's earnings were $408 million in 2001, $471 million in 2000 and $469 million in
1999.  The $63 million decrease in 2001 was primarily due to the February 2001 fire and resulting outage at San
Onofre Nuclear Generation Station Unit 3 and lower kilowatt-hour sales.  In 2000, superior operating performance
at San Onofre and higher kilowatt-hour sales were almost completely offset by adjustments to reflect potential
regulatory refunds and lower gains from sales of equity investments.

Accounting principles generally accepted in the United States require SCE at each financial statement date to
assess the probability of recovering its regulatory assets through a regulatory process.  Based on the rules
arising from the CPUC's March 27, 2001, rate stabilization decision, the $4.5 billion TRA undercollection as of
December 31, 2000, and the coal and hydroelectric balancing account overcollections were reclassified, and the
TCBA balance was recalculated to be a $2.9 billion undercollection (see further discussion of the CPUC rate
increase in the Rate Stabilization Proceeding section and the components of the TCBA undercollection in the
Status of Transition and Power-Procurement Cost Recovery section of Regulatory Environment).  As a result, SCE
was unable to conclude that, under applicable accounting principles, the $2.9 billion TCBA undercollection (as
recalculated above) and $1.3 billion (book value) of other net regulatory assets that were to be recovered
through the TCBA mechanism by the end of the rate freeze, were probable of recovery through the rate-making
process as of December 31, 2000.  As a result, SCE's December 31, 2000, income statement included a $4.0 billion
charge to provisions for regulatory adjustment clauses and a $1.5 billion net reduction in income tax expense, to
reflect the $2.5 billion (after tax) write-off.

Based on the rules arising from the CPUC's January 23, 2002, PROACT resolution, SCE was able to conclude that
$3.6 billion in regulatory assets previously written off were probable of recovery through the rate-making
process as of December 31, 2001.  As a result, SCE's December 31, 2001, consolidated income statement included a
$3.6 billion credit to provisions for regulatory adjustment clauses and a $1.5 billion charge to income tax
expense, to reflect the $2.1 billion (after tax) credit to earnings.

Operating Revenue

From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an
energy service provider (thus becoming direct access customers) or continue to have SCE purchase power on their
behalf.  Most direct access customers continued to be billed by SCE, but were given a credit for the generation
purchased from the energy service provider.  Operating revenue is reported net of this credit.  On September 20,
2001, the CPUC suspended the ability of retail customers to select alternative providers of electricity until the
California Department of Water Resources (CDWR) stops buying power for retail customers, pending further review
by the CPUC.  On March 21, 2002, the

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Management's Discussion and Analysis of Results of Operations and Financial Condition


CPUC issued a final decision affirming September 20, 2001, as the date when direct access was suspended in the
state.

During 2000, as a result of the power shortage in California, SCE's customers on interruptible rate programs
(which provide for lower generation rates with a provision that service can be interrupted if needed, with
penalties for noncompliance) were asked to curtail their electricity usage at various times.  As a result of
noncompliance with SCE's requests, those customers were assessed significant penalties.  On January 26, 2001, the
CPUC waived the penalties assessed to noncompliant customers after October 1, 2000, until the interruptible
programs can be reevaluated.

Operating revenue increased in 2001 (as shown in the table below), primarily due to the effects of the reduced
credits given to direct access customers in 2001 and the 4 cents-per-kWh (1 cent in January and 3 cents in June)
surcharge effective in 2001. The increases were partially offset by: a decrease in retail sales volume primarily
attributable to conservation efforts; a decrease in revenue related to penalties customers incurred for not
complying with their interruptible contracts; a decrease in revenue related to operation and maintenance
services; and a decrease in revenue related to electric power provided to SCE customers by the CDWR or
Independent System Operator (ISO).  Amounts SCE bills to and collects from its customers for electric power
purchased and sold by the CDWR or through the ISO on behalf of SCE's customers (beginning January 17, 2001) are
being remitted to the CDWR and are not recognized as revenue by SCE.  In 2001, this amount was $2.0 billion.  See
CDWR Power Purchases discussion.

Operating revenue increased in 2000 (as shown in the table below), primarily due to:  warmer weather in the
second and third quarters of 2000 as compared to the same periods in 1999; increased resale sales; and an
increase in revenue related to penalties customers incurred for not complying with their interruptible contracts.

The changes in operating revenue resulted from:

         In millions                Year ended December 31,                     2001         2000       1999
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         Operating revenue -
         Rate changes (including refunds)                                     $  422       $  120     $  (75)
         Direct access credit                                                    566         (434)      (213)
         Interruptible noncompliance penalty                                    (117)         102          6
         Sales volume changes                                                   (544)         520        195
         Other                                                                   (71)          14        136
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              Total                                                           $  256       $  322      $  49
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More than 94% of operating revenue was from retail sales.  Retail rates are regulated by the CPUC and wholesale
rates are regulated by the Federal Energy Regulatory Commission (FERC).

Due to warmer weather during the summer months, operating revenue during the third quarter of each year is
significantly higher than other quarters.

Operating Expenses

Fuel expense increased in 2001 and decreased in 2000.  The increase in 2001 and the decrease in 2000 were both
due to fuel-related refunds resulting from a settlement with another utility that SCE recorded in the second and
third quarters of 2000.

Purchased-power expense decreased in 2001 and increased in 2000.  The 2001 decrease resulted from the absence of
California Power Exchange (PX)/ISO purchased-power expense after mid-January 2001, partially offset by increased
expenses related to qualifying facilities (QFs), bilateral contracts and interutility contracts.  See Purchased
Power table in Note 1 to the Consolidated Financial Statements and discussion in CDWR Power Purchases.  PX/ISO
purchased-power expense increased significantly between May 2000 and mid-

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                                                                                Southern California Edison Company


January 2001, due to a number of factors, including increased demand for electricity in California, dramatic
price increases for natural gas (a key input of electricity production), and problems in the structure and
conduct of the PX and ISO markets.  In December 2000, the FERC eliminated the requirement that SCE buy and sell
all power through the PX and ISO.  Due to SCE's noncompliance with the PX's tariff requirement for posting
collateral for all transactions in the day-ahead and day-of markets as a result of the downgrade in its credit
rating, the PX suspended SCE's market trading privileges effective mid-January 2001.

Prior to April 1998, federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs
at CPUC-mandated prices even though energy and capacity prices under many of these contracts are generally higher
than other sources.  These contracts expire on various dates through 2025.  See further discussion regarding new
QF agreements in Litigation.  Purchased-power expense related to QFs increased due to the short-run avoided cost
factor (which is based on the price of natural gas) of the QF contracts causing a significant increase in the
payments to QFs.  In early 2001, structural problems in the market caused abnormally high gas prices.  The
increase related to bilateral contracts was the result of SCE not having these contracts in 2000.  The increase
related to interutility contracts was volume-driven.

SCE has contracts with certain QFs in which Edison Mission Energy (a wholly owned subsidiary of Edison
International) has 49% - 50% interests.  The terms and pricing of these contracts are approved by the CPUC.
SCE's power purchases from these facilities were $983 million in 2001, $716 million in 2000 and $513 million in
1999.

Provisions for regulatory adjustment clauses decreased for 2001 and increased for 2000.  The 2001 decrease
resulted from SCE recording the $3.6 billion PROACT regulatory asset in fourth quarter 2001.  The increase in
2000 was mainly due to SCE's write-off as of December 31, 2000, of $4.2 billion in regulatory assets and
liabilities as a result of the California energy crisis.  Adjustments to reflect potential regulatory refunds
related to the outcome of the CPUC's reevaluation of the operation of the interruptible rate programs also
contributed to the increase in 2000.

Other operation and maintenance expense decreased in 2000.  The decrease was primarily due to a $120 million
decrease in mandated transmission service (known as reliability must-run services) expense and a $19 million
decrease in operating expenses at San Onofre.  The decrease at San Onofre in 2000 was primarily due to scheduled
refueling outages for both units in the first half of 1999.  San Onofre had only one refueling outage in 2000.

Depreciation, decommissioning and amortization expense decreased in 2001, mainly due to SCE's nuclear investment
amortization expense ceasing since the unamortized nuclear investment regulatory asset was included in the
December 31, 2000, write-off.

Net gain on sale of utility plant in 2000 resulted from the sale of additional property related to four of the
generating stations SCE sold in 1998.  The gains were returned to the ratepayers through the TCBA mechanism.

Other Income and Deductions

Interest and dividend income increased in both 2001 and 2000.  The increase in 2001 was mainly due to an overall
higher cash balance, as SCE conserved cash due to its liquidity crisis.  The increase in 2000 was mostly due to
increases in interest earned on higher balancing account undercollections.

Other nonoperating income decreased in both 2001 and 2000.  The decrease in 2001 primarily reflects the gains on
sales of marketable securities in 2000.  The decrease in 2000 was primarily due to larger gains on sales of
marketable securities in 1999.

Interest expense - net of amounts capitalized increased in both 2001 and 2000.  The increase in 2001 reflects
additional long-term debt and higher short-term debt balances.  The increase in 2000 was mostly

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Management's Discussion and Analysis of Results of Operations and Financial Condition


due to higher overall short-term debt balances necessary to meet general cash requirements (especially PX and ISO
payments) and higher interest expense related to balancing account overcollections.

Other nonoperating deductions decreased in 2001 primarily due to lower accruals for regulatory matters in 2001.

Income Taxes

Income taxes increased in 2001 and decreased in 2000.  The increase in 2001 reflects $1.5 billion in income tax
expense related to the PROACT regulatory asset establishment in fourth quarter 2001.  The decrease in 2000 was
primarily due to the $1.5 billion income tax benefit related to the write-off as of December 31, 2000, of
regulatory assets and liabilities in the amount of $2.5 billion (after tax).  Absent the impact of the PROACT
regulatory asset in 2001 and the write-off in 2000, SCE's income tax expense increased in both 2001 and 2000 due
to higher pre-tax income in both years.

Financial Condition

SCE's liquidity is affected primarily by regulation affecting its ability to recover the cost of power purchases,
debt maturities, access to capital markets, credit ratings, dividend payments and capital expenditures.  Capital
resources include cash from operations and external financings.

Liquidity Issues

Sustained higher wholesale energy prices that began in May 2000 persisted through June 2001.  This resulted in
undercollections in the TRA and TCBA.  Undercollections, coupled with SCE's anticipated near-term capital
requirements (detailed in Projected Commitments) and the adverse reaction of the credit markets to continued
regulatory uncertainty regarding SCE's ability to recover its current and future power procurement costs,
materially and adversely affected SCE's liquidity throughout 2001.  As a result of its liquidity concerns, SCE
took steps to conserve cash to continue to provide service to its customers.  As a part of this process,
beginning in January 2001, SCE suspended payments owed to the ISO, the PX and QFs, deferred payments of certain
obligations for principal and interest on outstanding debt and did not declare dividends on any of its cumulative
preferred stock.  As applicable, unpaid obligations continued to accrue interest.  As of March 31, 2001, SCE
resumed payment of interest on its debt obligations.  However, since June 30, 2001, SCE deferred the interest
payments on its quarterly income debt securities (subordinated debentures), as allowed by the terms of the
securities.  All interest in arrears must be paid at the end of the deferral period.  As long as accumulated
dividends on SCE's preferred stock remain unpaid, SCE could not pay dividends on its common stock.  Common stock
dividends are additionally restricted as detailed in the CPUC Litigation Settlement discussion.

Based on the rights to cost recovery and revenue established by the settlement agreement with the CPUC and CPUC
implementing orders, including the PROACT resolution, SCE repaid its undisputed past-due obligations on March 1,
2002, with lump-sum payments to creditors from the proceeds of $1.6 billion in senior secured credit facilities,
the remarketing of $196 million in pollution-control bonds which were repurchased in late 2000, and existing cash
on hand.  The $1.6 billion senior secured credit facilities consist of a $300 million, two-year revolving credit
loan, a $600 million, one-year loan and a $700 million, three-year loan.

The proceeds from the senior secured credit facilities and pollution-control bond remarketing were used, along
with SCE's available cash, to repay $3.2 billion in past-due obligations and $1.65 billion in near-term debt
maturities.  The past-due obligations consisted of:  (1) $875 million to the PX; (2) $99 million to the ISO;
(3) $1.1 billion to QFs; (4) $193 million in PX energy credits for energy service providers; (5) $531 million of
matured commercial paper; (6) $400 million of principal on its 5-7/8% and 6-1/2% senior unsecured notes which
were issued prior to the energy crisis; and (7) $23 million in preferred dividends in arrears.  The near-term
debt maturities consisted of credit facilities whose maturity dates were extended several times and were
scheduled to mature in March and May 2002.  In addition, SCE entered into an agreement with the CDWR to pay for
prior deliveries of energy in installments of $100 million on April 1,

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                                                                                Southern California Edison Company


2002, $150 million on June 3, 2002, and the balance on July 1, 2002.  After making the above-described payments,
SCE has no material undisputed obligations that are past due or in default.

SCE expects to meet its continuing obligations from remaining cash on hand and future operating cash flows.

For additional discussion on the impact of California's energy crisis on SCE's liquidity, see Cash Flows from
Financing Activities.  For a discussion on the settlement agreement with the CPUC and the PROACT resolution to
resolve SCE's crisis, see CPUC Litigation Settlement Agreement and PROACT Regulatory Asset sections.

Cash Flows from Operating Activities

Net cash provided by operating activities was $3.3 billion in 2001, $829 million in 2000 and $1.5 billion in
1999.  The increase in 2001 was primarily due to SCE suspending payments for purchased power and other
obligations beginning in January 2001.  Cash provided by operating activities also reflects the CPUC-approved
surcharges (1 cent per kWh in January and 3 cent per kWh in June) that were billed in 2001.  The decrease in 2000
was the result of extremely high prices SCE paid for energy and ancillary services procured through the PX and
ISO.

Cash Flows from Financing Activities

At December 31, 2001, SCE had drawn on its entire credit lines of $1.65 billion.  These unsecured lines of credit
have various expiration dates and, when available, could be drawn down at negotiated or bank index rates.  On
March 1, 2002, SCE's credit lines ($1.65 billion) were repaid using proceeds from the March 1, 2002, financing.
See additional discussion in Liquidity Issues.

Short-term debt is used to finance balancing account undercollections, fuel inventories and general cash
requirements, including purchased-power payments.  Long-term debt is used mainly to finance capital
expenditures.  External financings are influenced by market conditions and other factors.  Because of the $2.5
billion charge to earnings as of December 31, 2000, SCE does not currently meet the interest coverage ratio that
is required for SCE to issue additional preferred stock.

As a result of investors' concerns regarding the California energy crisis and its impact on SCE's liquidity and
overall financial condition, during December 2000 and early 2001, SCE had to repurchase $550 million of
pollution-control bonds that could not be remarketed in accordance with their terms.  SCE remarketed $196 million
of these bonds in March 2002 (see additional discussion in Liquidity Issues).  The remaining amount of these
bonds may be remarketed in the future.  In addition, SCE remains unable to sell its commercial paper and other
short-term financial instruments.

Although Fitch IBCA, Standard & Poor's and Moody's Investors Service raised their credit ratings significantly
for SCE in March 2002, the new ratings are still below investment grade.  The new ratings reflect the ongoing
financial recovery of SCE that began in October 2001 with SCE's settlement agreement with the CPUC and has
continued with the CPUC's January 2002 PROACT resolution and the repayment of SCE's past-due obligations.  SCE
lost its investment-grade ratings in January 2001.

California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.  Additionally,
the CPUC regulates SCE's capital structure, thereby limiting the dividends it may pay Edison International.

In December 1997, $2.5 billion of rate reduction notes were issued on behalf of SCE by SCE Funding LLC, a special
purpose entity.  These notes were issued to finance the 10% rate reduction mandated by state law.  The proceeds
of the rate reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable right known as
transition property.  Transition property is a current property right created by the restructuring legislation
and a financing order of the CPUC and consists generally of the right to be paid a specified amount from
non-bypassable rates charged to residential and small commercial customers.  The rate reduction notes are being
repaid over 10 years through these non-bypassable residential and small commercial customer rates, which
constitute the transition property

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Management's Discussion and Analysis of Results of Operations and Financial Condition


purchased by SCE Funding LLC.  The remaining series of outstanding rate reduction notes have scheduled maturities
beginning in 2002 and ending in 2007, with interest rates ranging from 6.22% to 6.42%.  The notes are secured by
the transition property and are not secured by, or payable from, assets of SCE or Edison International.  SCE used
the proceeds from the sale of the transition property to retire debt and equity securities.  Although, as
required by accounting principles generally accepted in the United States, SCE Funding LLC is consolidated with
SCE and the rate reduction notes are shown as long-term debt in the consolidated financial statements, SCE
Funding LLC is legally separate from SCE.  The assets of SCE Funding LLC are not available to creditors of SCE or
Edison International and the transition property is legally not an asset of SCE or Edison International.  Due to
its credit rating downgrade in late 2000, in January 2001, SCE began remitting its customer collections related
to the rate-reduction notes on a daily basis.

Cash Flows from Investing Activities

Cash flows from investing activities are affected by additions to property and plant and funding of nuclear
decommissioning trusts.  Decommissioning costs are recovered in utility rates.  These costs are expected to be
funded from independent decommissioning trusts that receive SCE contributions of approximately $25 million per
year.  In 1995, the CPUC determined the restrictions related to the investments of these trusts.  They are: not
more than 50% of the fair market value of the qualified trusts may be invested in equity securities; not more
than 20% of the fair market value of the trusts may be invested in international equity securities; up to 100% of
the fair market values of the trusts may be invested in investment grade fixed-income securities including, but
not limited to, government, agency, municipal, corporate, mortgage-backed, asset-backed, non-dollar, and cash
equivalent securities; and derivatives of all descriptions are prohibited.  Contributions to the decommissioning
trusts are reviewed every three years by the CPUC.  The contributions are determined from an analysis of
estimated decommissioning costs, the current value of trust assets and long-term forecasts of cost escalation and
after-tax return on trust investments.  Favorable or unfavorable investment performance in a period will not
change the amount of contributions for that period.  However, trust performance for the three years leading up to
a CPUC review proceeding will provide input into future contributions.  SCE's costs to decommission San Onofre
Unit 1 are paid from the nuclear decommissioning trust funds.  These withdrawals from the decommissioning trusts
are netted with the contributions to the trust funds in the Consolidated Statements of Cash Flows.

Projected Commitments

SCE's projected construction expenditures for 2002 are $921 million.

Long-term debt maturities and sinking fund requirements for the next five years are:  2002 - $1.1 billion; 2003 -
$1.4 billion; 2004 - $371 million; 2005 - $246 million; and 2006 - $446 million.

Fuel supply contract payments for the next five years are:  2002 - $168 million; 2003 - $108 million; 2004 - $103
million; 2005 - $106 million; and 2006 - $109 million.

Purchased-power capacity payments for the next five years are:  2002 - $629 million; 2003 - $629 million; 2004 -
$626 million; 2005 - $624 million; and 2006 - $572 million.

Preferred stock redemption requirements for the next five years are:  2002 - $105 million; 2003 - $9 million;
2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.

Market Risk Exposures

SCE's primary market risk exposures include commodity price risk and interest rate risk that could adversely
affect results of operations or financial position.  Commodity price risk arises from fluctuations in the market
price of an energy commodity, such as electricity, natural gas, or coal.  Interest rate risk arises from
fluctuations in interest rates.  Additionally, natural gas is a key input for the prices specified in
approximately half of SCE's QF (including non-gas QF) contracts.  Virtually all of SCE's exposure to changes in
the spot market price for natural gas through 2003 is hedged through financial derivatives or fixed-price
contracts.  SCE's risk management policy allows the use of derivative financial instruments to

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                                                                                Southern California Edison Company


manage its financial exposures, but prohibits the use of these instruments for speculative or trading purposes.

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used
for liquidity purposes and to fund business operations, as well as to finance capital expenditures.  The nature
and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business
requirements, market conditions and other factors.  As a result of California's energy crisis, SCE has been
exposed to significantly higher interest rates, which intensified its liquidity crisis during 2001 (further
discussed in the Liquidity Issues section of Financial Condition).

At December 31, 2001, SCE did not believe that its short-term debt was subject to interest rate risk, due to the
fair market value being approximately equal to its carrying value.  SCE did believe that the fair market value of
its fixed-rate long-term debt was subject to interest rate risk.  At December 31, 2001, a 10% increase in market
interest rates would have resulted in a $128 million decrease in the fair market value of SCE's long-term debt.
A 10% decrease in market interest rates would have resulted in a $141 million increase in the fair market value
of SCE's long-term debt.

Since April 1998, the price SCE paid to acquire power on behalf of customers was allowed to float, in accordance
with the 1996 electric utility restructuring law.  Until May 2000, retail rates were sufficient to cover the cost
of power and other SCE costs.  However, between May 2000 and June 2001, market power prices escalated, creating a
substantial gap between costs and retail rates.  In response to the dramatically higher prices, the ISO and the
FERC have placed certain caps on the price of power (see further discussion in Wholesale Electricity Markets).

Under the terms of the CPUC settlement agreement, SCE purchased $209 million in hedging instruments (gas call
options) in October and November 2001 to hedge a majority of its natural gas price exposure associated with QF
contracts for 2002 and 2003.  Although these gas call options are reflected in the income statement, any fair
value changes of the gas call options are offset through a regulatory balancing account; therefore, fair value
changes do not affect earnings.  At December 31, 2001, a 10% increase in market gas prices would have resulted in
a $32 million increase in the fair market value of SCE's gas call options.  A 10% decrease in market gas prices
would have resulted in a $27 million decrease in the fair market value of the gas call options.

In accordance with an accounting standard for derivatives, on January 1, 2001, SCE recorded its block-forward
contracts at fair value on the balance sheet.  Because SCE suspended payments for purchased power on January 16,
2001, the PX sought to liquidate SCE's remaining block-forward contracts.  Before the PX could do so, on
February 2, 2001, the state seized the contracts.  On September 20, 2001, a federal appeals court ruled that the
governor of California acted illegally when he seized the power contracts held by SCE.  In conjunction with its
settlement agreement with the CPUC (discussed in CPUC Litigation Settlement Agreement), SCE has agreed to release
any claim for compensation against the state for these contracts.  However, if the PX prevails in its claims
against the state, SCE may receive some refunds.  Due to its speculative grade credit ratings, SCE has been
unable to purchase additional bilateral forward contracts, and some of the existing contracts were terminated by
the counterparties.

Regulatory Environment

SCE operates in a highly regulated environment and has an exclusive franchise within its service territory.  SCE
has an obligation to deliver electric service to its customers and regulatory authorities have an obligation to
provide just and reasonable rates.  In the mid-1990s, state lawmakers and the CPUC initiated the electric
industry restructuring process.  SCE was directed by the CPUC to divest the bulk of its gas-fired generation
portfolio.  Today, independent power companies own the divested generating plants.  The electric industry
restructuring plan also instituted a multi-year freeze on the rates that SCE could charge its customers and
transition cost recovery mechanisms (as described in Status of Transition and Power-Procurement Cost Recovery)
designed to allow SCE to recover its stranded costs associated with generation-related assets.  California's
electric industry restructuring statute included provisions to finance a portion of the stranded costs that
residential and small commercial customers would have paid between

Page 9


-------------------------------------------------------------------------------------------------------------------
Management's Discussion and Analysis of Results of Operations and Financial Condition


1998 and 2001, which allowed SCE to reduce rates by at least 10% to these customers, effective January 1, 1998.
These frozen rates (except for the surcharge effective in 2001) were to remain in effect until the earlier of
March 31, 2002, or the date when the CPUC-authorized costs for utility-owned generation assets and obligations
are recovered.  However, between May 2000 and June 2001, the prices charged by sellers of power escalated far
beyond what SCE could charge its customers.  As a result, SCE incurred $2.7 billion (after tax), or $4.7 billion
(pre-tax), in write-offs as of December 31, 2000, and net undercollected transition costs through August 31,
2001.  As indicated below, implementation of the CPUC settlement agreement and CPUC approval of SCE's
Utility-Retained Generation (URG) application is expected to allow SCE to recover substantially all of the $4.7
billion.

Generation and Power Procurement

During the rate freeze, recovery of generation-related transition costs was tracked through the TCBA mechanism.
Revenue from generation-related operations was determined through the market and transition cost recovery
mechanisms, which included the nuclear rate-making agreements.  During fourth quarter 2001, the TCBA mechanism
was terminated retroactive to September 1, 2001, and a $3.6 billion PROACT regulatory asset was created in
accordance with the October 2001 settlement agreement with the CPUC and the PROACT resolution adopted in January
2002.  In accordance with a state law passed in January 2001, SCE will continue to own its remaining generation
assets, which will be subject to cost-based ratemaking, through 2006 (see further discussion in URG Proceeding).

Through December 31, 2000, SCE had been recovering its investment in its nuclear facilities on an accelerated
basis (over four years) in exchange for a lower authorized rate of return on investment.  SCE's nuclear assets
were earning an annual rate of return on investment of 7.35%.  However, due to the various unresolved regulatory
and legislative issues (as discussed in Status of Transition and Power-Procurement Cost Recovery), as of
December 31, 2000, SCE was no longer able to conclude that the $610 million balance of unamortized nuclear
investment regulatory assets was probable of recovery through the rate-making process.  As a result, this balance
was written off as a charge to earnings at that time (see further discussion in Earnings).  Should the URG
application be approved, SCE expects to reestablish for financial reporting purposes its unamortized nuclear
investment and related flow-through taxes retroactive to August 31, 2001, with recovery based on a 10-year
period, effective January 1, 2001, with a corresponding credit to earnings, and adjust the PROACT regulatory
asset balance as necessary to reflect recovery of the nuclear investment in accordance with the final URG
decision.

The San Onofre incentive-pricing plan authorizes a fixed rate of approximately 4 cent per kWh generated for
operating costs including incremental capital costs, nuclear fuel and nuclear fuel financing costs.  The
San Onofre incentive-pricing plan started in April 1996 and ends in December 2003.  The Palo Verde Nuclear
Generating Station's operating costs, including incremental capital costs, and nuclear fuel and nuclear fuel
financing costs, were subject to balancing account treatment.  The Palo Verde plan started in January 1997 and
was to end in December 2001.  The benefits of operation of the San Onofre units and the Palo Verde units were
required to be shared equally with ratepayers beginning in 2004 and 2002, respectively. In a June 2001 decision,
the CPUC granted SCE's request to eliminate the San Onofre post-2003 sharing mechanism based on compliance with a
state law enacted in early 2001.  In a September 2001 decision, the CPUC granted SCE's request to eliminate the
Palo Verde post-2001 sharing mechanism and to continue the current rate-making treatment for Palo Verde,
including the continuation of the existing nuclear incentive procedure with a 5 cents per kWh cap on replacement
power costs, until resolution of SCE's next general rate case or further CPUC action.  Beginning January 1, 1998,
both the San Onofre and Palo Verde rate-making plans became part of the TCBA mechanism.  These rate-making plans
and the TCBA mechanism were to continue for rate-making purposes at least through the end of the rate freeze
period.  However, in its URG application, SCE proposed to move the recovery of nuclear costs to another balancing
account mechanism.  See discussion in URG Proceeding for the proposed and alternate decisions' impact on the
incentive-pricing plans.

CPUC Litigation Settlement Agreement
------------------------------------

In November 2000, SCE filed a lawsuit against the CPUC in federal district court seeking a ruling that SCE is
entitled to full recovery of its past electricity procurement costs in accordance with the tariffs filed with

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                                                                                Southern California Edison Company


the FERC.  By agreement of the parties, a stay of the lawsuit was issued in April 2001 while SCE sought
implementation of legislative, regulatory and executive actions to resolve the California energy crisis and SCE's
related financial and liquidity problems.  In October 2001, the federal district court entered a stipulated
judgment approving an agreement between the CPUC and SCE to settle the pending lawsuit.  On January 23, 2002, the
CPUC adopted a resolution implementing the settlement agreement.  See discussion below in PROACT Regulatory
Asset.

Key elements of the settlement agreement include the following items:

o        Establishment of the PROACT, as of September 1, 2001, with an opening balance equal to the amount of
     SCE's procurement-related liabilities as of August 31, 2001 (approximately $6.4 billion), less SCE's cash and
     cash equivalents as of that date (approximately $2.5 billion), and less $300 million.

o        Beginning on September 1, 2001, SCE will apply to the PROACT, on a monthly basis, the difference between
     SCE's revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the
     CPUC to recover in retail electric rates.  Unrecovered obligations in the PROACT will accrue interest from
     September 1, 2001.

o        Maintain current rates (including surcharges) in effect until December 31, 2003, subject to certain
     adjustments, or, if earlier, until the date that SCE recovers the entire PROACT balance.  If SCE has not
     recovered the entire balance by December 31, 2003, the unrecovered balance will be amortized for up to an
     additional two years.  The parties project that existing retail electric rates, including surcharges and as
     adjusted to reflect certain costs, will likely result in SCE recovering substantially all of its unrecovered
     procurement-related obligations prior to the end of 2003.

o        If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's
     procurement-related obligations, the parties will work together to achieve the securitization.  Proceeds of
     any securitization will be credited to the PROACT when they are actually received.

o        During the period that SCE is recovering its previously incurred procurement-related obligations, no
     penalty will be imposed by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure
     requirements.

o        SCE can incur up to $250 million of recoverable costs to acquire financial instruments and engage in
     other transactions intended to hedge fuel cost risks associated with SCE's retained generation assets and
     power purchase contracts with QFs and other utilities.  As of December 31, 2001, SCE had purchased $209
     million in hedging instruments.  See discussion in Market Risk Exposures.

o        SCE will not declare or pay dividends or other distributions on its common stock (all of which is held
     by its parent) prior to the earlier of the date SCE has recovered all of its procurement-related obligations
     in the PROACT or January 1, 2005.  However, if SCE has not recovered all of its procurement-related
     obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common stock dividends,
     and the CPUC will not unreasonably withhold its consent.

o        To ensure the ability of SCE to continue to provide adequate service, SCE may make capital expenditures
     above the level contained in current rates, up to $900 million per year, which will be treated as
     recoverable costs.

o        Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General
to pursue and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses to
claims arising from any failure to make payments to the PX or ISO, and similar claims by the State of California
or its agencies against the same adverse parties.  During the recovery period discussed above, refunds obtained
by SCE related to its procurement-related liabilities will be applied to the balance in the PROACT.

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Management's Discussion and Analysis of Results of Operations and Financial Condition


The settlement agreement states that one of its purposes is to restore the investment grade creditworthiness of
SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a
state-regulated entity as it has in the past.  SCE cannot provide assurance that it will regain investment grade
credit ratings by any particular date.

On November 28, 2001, a federal court of appeals denied a California consumer group's request for a long-term
stay of the settlement.  The group had alleged that it was denied due process and that the CPUC had no authority
to agree with SCE to violate the statutory rate freeze.  In its ruling, the federal court of appeals also granted
SCE's request for an expedited hearing of an appeal of the settlement filed by the consumer group.  On March 4,
2002, the court of appeals heard argument on the appeal and the matter is now under submission.  A decision could
be issued anytime during the next several months.  SCE cannot predict the outcome of the appeal or the impact
that any outcome would have upon the stipulated judgment or the settlement, at this time.  Possible outcomes
include affirmance, a return to the district court or reversal of the stipulated judgment.  SCE cannot predict
whether or how a ruling on the stipulated judgment could also affect the settlement agreement.

PROACT Regulatory Asset
-----------------------

According to the terms of the settlement agreement and the CPUC resolution, in the fourth quarter of 2001, SCE
established (retroactive to August 31, 2001) a $3.6 billion PROACT regulatory asset for its previously incurred
procurement costs.

The beginning balance of the PROACT, as verified by the CPUC, was calculated as follows:

              In millions
--------------------------------------------------------------------------------------------------

              Past-due bills:
                 PX or ISO                                                               $    924
                 QFs                                                                        1,219
                 PX energy credits                                                            236
                 Imbalance energy (CDWR)                                                      383
                 Ancillary services for resale cities                                          30
--------------------------------------------------------------------------------------------------

                  Total past-due bills                                                      2,792
--------------------------------------------------------------------------------------------------

              Procurement-related debt (including accrued interest):
                 Credit facilities                                                          1,298
                 Bilateral credit facilities                                                  415
                 Defaulted commercial paper                                                   563
                 Floating rate notes due May 2002                                             313
                 Variable rate notes due November 2003                                      1,043
--------------------------------------------------------------------------------------------------

                  Total procurement-related debt                                            3,632
--------------------------------------------------------------------------------------------------

              Total procurement-related liabilities                                         6,424
              Less:  Cash and cash equivalents on hand                                     (2,547)
              Less:  Amount stipulated in agreement                                          (300)
--------------------------------------------------------------------------------------------------

              Net PROACT balance as of August 31, 2001                                    $ 3,577
--------------------------------------------------------------------------------------------------


For a comparison between the PROACT balance as of August 31, 2001, and the TCBA balance as of that date, see
discussion in Status of Transition and Power-Procurement Cost Recovery.

CDWR Power Purchases
--------------------

In accordance with an emergency order signed by the governor, the CDWR began making emergency power purchases for
SCE's customers on January 17, 2001.  Amounts SCE bills to and collects from its customers for electric power
purchased and sold by the CDWR and through the ISO are remitted directly to the CDWR and are not recognized as
revenue by SCE.  In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1X) was enacted into law.
AB 1X authorized the CDWR to enter into contracts

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                                                                                Southern California Edison Company


to purchase electric power and sell power at cost directly to retail customers being served by SCE, and
authorized the CDWR to issue bonds to finance electricity purchases.

On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to the
applicable generation-related retail rate per kWh for electricity (based on rates in effect on January 5, 2001),
for each kWh the CDWR sells to SCE's customers.  The CPUC determined that the generation-related retail rate
should be equal to the total bundled electric rate (including the 1 cent-per-kWh surcharge adopted by the CPUC on
January 4, 2001) less certain nongeneration-related rates or charges.  For the period January 19 through January
31, 2001, the CPUC ordered SCE to pay the CDWR at a rate of 6.277 cents per kWh for power delivered to SCE's
customers.  The CPUC determined that the applicable rate component is 7.277 cents per kWh (which increased to
10.277 cents per kWh for electricity delivered after March 27, 2001, due to the 3 cents-surcharge discussed in
Rate Stabilization Proceedings), for electricity delivered by the CDWR to SCE's retail customers after
February 1, 2001, until more specific rates are calculated.  The CPUC ordered SCE to pay the CDWR within 45 days
after the CDWR supplies power to retail customers, subject to penalties for each day the payment is late.

On February 21, 2002, the CPUC issued a decision implementing a CDWR revenue requirement of $9.0 billion to pay
its bonds' costs and energy procurement costs for the period January 17, 2001, through December 31, 2002.  The
decision states that SCE's allocated share of this revenue requirement would be approximately $3.6 billion, and
changes SCE's payment to 9.744 cents per kWh for all bills rendered on or after March 15, 2002.  The decision
requires SCE to pay the CDWR in equal monthly installments over a six-month period the difference in rates
between January 17, 2001, and March 15, 2002.  SCE estimates that this amount could be approximately $41
million.

On February 28, 2002, SCE and the CDWR executed an agreement that resolves outstanding issues relating to the
payment for electric power purchased for SCE's customers through the ISO real-time market (known as imbalance
energy).  Under this agreement, SCE will pay the CDWR for imbalance energy previously delivered in three
installments ($100 million on April 1, 2002; $150 million on June 3, 2002; and the balance on July 1, 2002).

Status of Transition and Power-Procurement Cost Recovery
--------------------------------------------------------

SCE's transition costs to be recovered through the TCBA mechanism included power purchases from QF contracts
(which are the direct result of prior legislative and regulatory mandates), recovery of certain generating assets
and other costs incurred to provide service to customers.  Other costs included the recovery of income tax
benefits previously flowed through to customers, postretirement benefit transition costs and accelerated recovery
of investment in nuclear generating units.  Recovery of costs related to power-purchase QF contracts was
permitted through the terms of each contract.  Legislation and regulatory decisions issued prior to the beginning
of the rate freeze called for most of the remaining transition costs to be recovered through the end of the
four-year transition period (not later than March 31, 2002).  Because regulatory and legislative actions that
make such recovery probable were not taken in a timely manner during the energy crisis, as of December 31, 2000,
SCE was unable to conclude that the net regulatory assets related to purchased-power settlements, the unamortized
loss on SCE's generating plant sales in 1998, and various other generation regulatory assets were probable of
recovery through the rate-making process.  As a result, these balances were written off as a charge to earnings
at that time (see further discussion in Earnings).

There were three sources of revenue available to SCE for transition cost recovery through the TCBA mechanism:
revenue from the sale or valuation of generation assets in excess of book values, net market revenue from the
sale of SCE-controlled generation into the ISO and PX markets and competition transition charge (CTC) revenue.
Revenue from the first two sources has not been available since January 2001.  Net proceeds of the 1998 plant
sales were used to reduce transition costs, which otherwise had been expected to be collected through the TCBA
mechanism.  However, state legislation enacted in January 2001 prohibits the sale of SCE's remaining generation
assets until 2006.  SCE stopped selling power from its generation into the ISO and PX markets in January 2001,
after SCE's credit ratings were downgraded and the PX suspended SCE's trading privileges (see discussion in
Generation and Power Procurement).


Page 13


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Management's Discussion and Analysis of Results of Operations and Financial Condition


CTC revenue was determined residually (i.e., CTC revenue was the residual amount remaining from monthly gross
customer revenue under the rate freeze after subtracting the revenue requirements for transmission, distribution,
nuclear decommissioning and public benefit programs, and ISO payments and power purchases from the PX and ISO).
The CTC applied to all customers who were using or began using utility services on or after the CPUC's 1995
restructuring decision date.  Residual CTC revenue was calculated through the TRA mechanism.  In accordance with
the March 27, 2001, rate stabilization decision, both positive and negative residual CTC revenue was transferred
from the TRA to the TCBA on a monthly basis, retroactive to January 1, 1998 (see further discussion in Rate
Stabilization Proceedings).  A previous decision had called only for a transfer of positive residual CTC revenue
(TRA overcollections) to the TCBA and there had not been any positive residual CTC revenue between May 2000 and
June 2001.

Because the regulatory and legislative actions that made such recovery probable were not taken, SCE was unable to
conclude as of December 31, 2000, that the recalculated TCBA net undercollection was probable of recovery through
the rate-making process.  As a result, the $2.9 billion TCBA net undercollection was written off as a charge to
earnings as of that date (see further discussion in Earnings), and an additional $552 million (pre-tax) of net
undercollected transition costs was charged to earnings between January 1, 2001, and August 31, 2001.  Although
the TCBA was written off, SCE continued to calculate the account for rate-making purposes, and the account
reflected a $4.2 billion undercollection as of August 31, 2001, the effective date of the beginning of the PROACT
mechanism and the end of the TCBA mechanism.  If the TCBA would have been adjusted for the impact of SCE's
treatment of the nuclear facilities as proposed in the URG proceeding, the TCBA balance as of August 31, 2001,
would have reflected an undercollection of $3.626 billion, substantially equal to the $3.577 billion
undercollection in the PROACT regulatory asset.

For more details on the matters discussed above, see discussions in Rate Stabilization Proceedings,
URG Proceeding and PROACT Regulatory Asset.

Litigation
----------

In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International.  As
amended in December 2000 and March 2001, the lawsuit involves securities fraud claims arising from alleged
improper accounting for the TRA undercollections.  The second amended complaint is supposedly filed on behalf of
a class of persons who purchased Edison International common stock between July 21, 2000, and April 17, 2001.
This lawsuit has been consolidated with another similar lawsuit filed on March 15, 2001.  A consolidated class
action complaint was filed on August 3, 2001.  On September 17, 2001, SCE and Edison International filed a motion
to dismiss for failure to state a claim.  On March 8, 2002, the district court issued an order dismissing the
complaint with prejudice.  The plaintiffs could appeal this ruling to the court of appeals.

In addition to the lawsuits filed against Edison International and SCE discussed above, SCE has been a defendant
in a number of legal actions brought by various QFs arising out of SCE's suspension of payments for electricity
delivered by the QFs during the period November 1, 2000, through March 26, 2001.  The QF claims were eventually
largely subsumed within agreements with the litigating QFs providing for a provisional settlement of the parties'
disputes.  On March 1, 2002, SCE paid the amounts due under settlement agreements with these QFs, which triggered
the releases and other provisions of the settlements.  As a result, the litigation with those QFs to whom payment
in full has been made under the parties' settlement agreements should be dismissed during 2002.  However, SCE's
March 1, 2002, payments excluded several QFs or did not result in immediate releases under the settlement
agreements based on unique disputes or other unique circumstances, including the status of regulatory approval.

Rate Stabilization Proceedings
------------------------------

In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the
four-year rate freeze was to end on March 31, 2002, or earlier, depending on the pace of transition cost
recovery.  In December 2000, SCE filed an amended rate stabilization plan application, stating that the statutory
rate freeze had ended in accordance with California law, and requesting the CPUC to approve an immediate 30%
increase to be effective, subject to refund, January 4, 2001.


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                                                                                Southern California Edison Company


In January 2001, independent auditors hired by the CPUC issued a report on the financial condition and solvency
of SCE and its affiliates.  The report confirmed what SCE had previously disclosed to the CPUC in public filings
about SCE's financial condition.  The audit report covered, among other things, cash needs, credit relationships,
accounting mechanisms to track stranded cost recovery, the flow of funds between SCE and Edison International,
and earnings of SCE's California affiliates.  In April 2001, the CPUC adopted an order instituting investigation
that reopens the past CPUC decision authorizing the utilities to form holding companies and initiates an
investigation into:  whether the holding companies violated CPUC requirements to give first priority to the
capital needs of their respective utility subsidiaries; whether ring-fencing actions by Edison International and
PG&E Corporation and their respective nonutility affiliates also violated the requirements to give priority to
the capital needs of their utility subsidiaries; whether the payment of dividends by the utilities violated
requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility
companies; any additional suspected violations of laws or CPUC rules and decisions; and whether additional rules,
conditions, or other changes to the holding company decisions are necessary.  The CPUC ordered testimony and
briefing on these matters, which SCE filed in May and June 2001.  On January 9, 2002, the CPUC issued an interim
decision on the first priority condition.  The decision stated that, at least under certain circumstances, the
condition includes the requirement that holding companies infuse all types of capital into their respective
utility subsidiaries when necessary to fulfill the utility's obligation to serve.  On February 11, 2002, SCE
filed an application for rehearing of the decision stating that the decision is an unlawful and erroneous attempt
to rewrite the first priority condition rather than interpret it and that the decision would result in higher
rates for SCE's customers.  SCE cannot predict what effects this investigation or any subsequent actions by the
CPUC may have on SCE.

In March 2001, the CPUC ordered a rate increase in the form of a 3 cents-per-kWh surcharge applied only to
going-forward electric power procurement costs and affirmed that a 1 cent interim surcharge granted in January
2001 is permanent.  The 3 cents surcharge is to be added to the rate paid to the CDWR (see CDWR Power
Purchases).  Although the 3 cents-increase was authorized as of March 27, 2001, the surcharge was not collected
in rates until the CPUC established a rate design in early June 2001.  To compensate for the two-month delay in
collecting the 3 cents surcharge, the CPUC authorized an additional1/2cent surcharge for a 12-month period
beginning in June 2001.

URG Proceeding
--------------

In June 2001, SCE filed a comprehensive proposal for new cost-of-service ratemaking for utility retained
generation through the end of 2002.  After that time, SCE's URG-related revenue requirement will be determined by
the general rate case.  The URG proposal calls for balancing accounts for SCE-owned generation, QF and
interutility contracts, procurement costs and ISO charges based on either actual or CPUC-authorized revenue
requirements.  Under the proposal, the four new balancing accounts would be effective January 1, 2001, for
capital-related costs, and February 1, 2001, for non-capital-related costs.  In addition, SCE's unamortized
nuclear investment would be amortized and recovered in rates over a 10-year period, effective January 1, 2001.
Should this application be approved as filed, SCE expects to reestablish for financial reporting purposes its
unamortized nuclear investment and regulatory assets related to purchased-power settlements and flow-through
taxes, with a corresponding credit to earnings, and adjust the PROACT regulatory asset balance in accordance with
the final URG decision.

On January 18, 2002, a CPUC administrative law judge issued a proposed decision and a CPUC commissioner issued an
alternate proposed decision.  Both the proposed and alternate proposed decisions adopt most of the elements of
SCE's application, but propose eliminating an incentive-pricing plan for San Onofre, effective January 1, 2002,
and replacing it with balancing account treatment for San Onofre's operating costs, subject to a later
reasonableness review.  On February 7, 2002, another CPUC commissioner issued an alternate proposed decision
recommending continuing the incentive-pricing plan for San Onofre Units 2 and 3 through December 31, 2003, as
originally provided in CPUC decisions adopted in early 1996.  A final decision is expected in second quarter 2002.


Page 15


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Management's Discussion and Analysis of Results of Operations and Financial Condition


Generation Procurement Proceeding
---------------------------------

In October 2001, the CPUC issued an order instituting rulemaking (OIR) to establish policies and cost recovery
mechanisms for generation procurement.  The OIR directed SCE and the other major California electric utilities to
provide recommendations for establishing these policies and mechanisms to enable the utilities to resume their
power procurement responsibilities in 2003.  In comments filed with the CPUC on November 26, 2001, SCE
recommended that the CPUC issue a procurement framework decision in February 2002, and direct the utilities to
submit their specific procurement plan proposals and related framework compliance proposals in March 2002.  SCE
also proposed that a final decision be issued in October 2002 adopting utility-specific procurement plans.  The
CPUC has not yet acted on SCE's recommendations, but is expected in second quarter 2002 to issue a scoping memo
setting forth issues to be addressed in this proceeding.

Accounting for Generation-Related Assets and Power Procurement Costs
--------------------------------------------------------------------

In 1997, SCE discontinued application of accounting principles for rate-regulated enterprises for its generation
assets.  At that time, SCE did not write off any of its generation-related assets, including related regulatory
assets, because the electric utility industry restructuring plan made probable their recovery through a
non-bypassable charge to distribution customers.

During the second quarter of 1998, in accordance with asset impairment accounting standards, SCE reduced its
remaining nuclear plant investment by $2.6 billion (as of June 30, 1998) and recorded a regulatory asset on its
balance sheet for the same amount.  For this impairment assessment, the fair value of the investment was
calculated by discounting expected future net cash flows.  This reclassification had no effect on SCE's results
of operations.

As of December 31, 2000, SCE assessed the probability of recovery of its generation-related assets and power
procurement costs in light of the CPUC's March 27, 2001, and April 3, 2001, decisions, and could not conclude
that its $2.9 billion TCBA undercollection (as redefined in the March 27 decisions) and $1.3 billion (book value)
of its net generation-related regulatory assets to be amortized into the TCBA, were probable of recovery through
the rate-making process.  As a result, accounting principles generally accepted in the United States required
that the balances in the accounts be written off as a charge to earnings.  In addition to the $4.2 billion
pre-tax write-off, SCE incurred approximately $552 million (pre-tax) in net undercollected transition costs
through August 31, 2001 (see Earnings).

In accordance with the CPUC settlement agreement and the PROACT resolution, in fourth quarter 2001, SCE
established a $3.6 billion regulatory asset for previously incurred power procurement costs, called the PROACT,
retroactive to August 31, 2001.  See further discussion in PROACT Regulatory Asset.  CPUC approval of the URG
application, as filed (see URG Proceeding), together with implementation of the PROACT mechanism is expected to
allow SCE to recover substantially all of the $4.7 billion in write-offs as of December 31, 2000, and net
undercollected transition costs incurred through August 31, 2001.

If the CPUC approves SCE's URG application, as filed, SCE expects to reapply accounting principles for
rate-regulated enterprises for its generation assets.  These assets will then be subject to traditional
cost-of-service regulation.

Distribution

Revenue related to distribution operations is determined through a performance-based rate-making (PBR) mechanism
and the distribution assets have the opportunity to earn a CPUC-authorized 9.49% return on investment.  Key
elements of the distribution PBR include:  distribution rates indexed for inflation based on the Consumer Price
Index less a productivity factor; adjustments for cost changes that are not within SCE's control; a
cost-of-capital trigger mechanism based on changes in a utility bond index; standards for customer satisfaction;
service reliability and safety; and a net revenue-sharing mechanism that determines how customers and
shareholders will share gains and losses from distribution operations.  The distribution PBR was to have ended in
December 2001, but in June 2001 the CPUC extended the mechanism until SCE's next general rate case, which will be
effective in 2003.  A CPUC proposed decision on the PBR

Page 16

------------------------------------------------------------------------------------------------------------------
                                                                                Southern California Edison Company


mechanism for 2002 was issued in January 2002.  The proposed decision authorized SCE to use a formula to
determine its distribution revenue requirement for the last half of 2001 and 2002, and a revenue balancing
account to ensure that variations in sales do not result in under or overcollections.  A final decision is
expected in second quarter 2002.  At this time, SCE cannot predict the effect of the final decision on its
results of operations.

In December 2001, SCE filed its 2003 general rate case with the CPUC, requesting an increase of approximately
$500 million in revenue (compared to 2000 recorded revenue) for its distribution and generation operations.
Hearings are expected to begin in July 2002, with a final decision expected in second quarter 2003.

Transmission

Transmission revenue is determined through FERC-authorized rates and is subject to refund.

Wholesale Electricity Markets

In October 2000, SCE filed a joint petition urging the FERC to immediately find the California wholesale
electricity market to be not workably competitive, immediately impose a cap on the price for energy and ancillary
services, and institute further expedited proceedings regarding the market failure, mitigation of market power,
structural solutions and responsibility for refunds.  In December 2000, the FERC took limited action and failed
to impose a price cap.  SCE filed an emergency petition in the federal court of appeals challenging the FERC
order and requesting the FERC to immediately establish cost-based wholesale rates.  The court denied SCE's
petition in January 2001.

In its December 2000 order, the FERC established an underscheduling penalty effective January 1, 2001, applicable
to scheduling coordinators that do not schedule sufficient resources to supply 95% of their respective loads.  In
December 2001, the FERC eliminated the underscheduling penalty retroactive to January 1, 2001.

On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy
price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power).  The order
establishes an hourly clearing price based on the costs of the least efficient generating unit during the
period.  Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency periods
and price mitigation in the 11-state western region.  The latest order is in effect until September 30, 2002.

After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25,
2001, the FERC issued an order that limits potential refunds from alleged overcharges to the ISO and PX spot
markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on
daily spot market gas prices.  An administrative law judge will conduct evidentiary hearings on this matter.  SCE
cannot predict the amount of any potential refunds.  Under the settlement of litigation with the CPUC, refunds
will be applied to the balance in the PROACT.

Environmental Protection

SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to
operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past
operations on the environment.

As further discussed in Note 12 to the Consolidated Financial Statements, SCE records its environmental
liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup
costs can be estimated.  SCE's recorded estimated minimum liability to remediate its 42 identified sites is $111
million.  SCE believes that, due to uncertainties inherent in the estimation process, it is reasonably possible
that cleanup costs could exceed its recorded liability by up to $279 million.  In 1998, SCE sold all of its
gas-fueled power plants but has retained some liability associated with the divested properties.


Page 17


-------------------------------------------------------------------------------------------------------------------
Management's Discussion and Analysis of Results of Operations and Financial Condition


The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $50 million of its
recorded liability, through an incentive mechanism, which is discussed in Note 12.  SCE has recorded a regulatory
asset of $76 million for its estimated minimum environmental-cleanup costs expected to be recovered through
customer rates.

SCE's identified sites include several sites for which there is a lack of currently available information.  As a
result, no reasonable estimate of cleanup costs can be made for these sites.  SCE expects to clean up its
identified sites over a period of up to 30 years.  Remediation costs in each of the next several years are
expected to range from $10 million to $25 million.  Recorded costs for the year ended December 31, 2001, were $18
million.

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the
upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental-cleanup
costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or
financial position.  There can be no assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will not require material revisions to such
estimates.

The Clean Air Act requires power producers to have emissions allowances to emit sulfur dioxide.  Power companies
receive emissions allowances from the federal government and may bank or sell excess allowances.  SCE expects to
have excess allowances under Phase II of the Clean Air Act (2000 and later).  A study was undertaken to determine
the specific impact of air contaminant emissions from the Mohave Generating Station on visibility in Grand Canyon
National Park.  The final report on this study, which was issued in March 1999, found negligible correlation
between measured Mohave station tracer concentrations and visibility impairment.  The absence of any obvious
relationship cannot rule out Mohave station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze.  In June 1999, the Environmental Protection
Agency (EPA) issued an advanced notice of proposed rulemaking regarding assessment of visibility impairment at
the Grand Canyon.  The EPA issued its final rule on February 8, 2002, which incorporates the terms of the consent
decree into the visibility provisions of its Federal Implementation Plan for Nevada, making the terms of the
consent decree federally enforceable.

SCE's share of the costs of complying with the consent decree and taking other actions to continue operation of
the Mohave station is estimated to be approximately $560 million over the next four years.  However, SCE has
suspended its efforts to seek approval to install the Mohave controls because it has not obtained reasonable
assurance of an adequate coal supply for operating Mohave beyond 2005.  If an adequate coal supply is not
obtained, it will become necessary to shut down the Mohave station after December 31, 2005.  If the station is
shut down at that time, the shutdown is not expected to have a material adverse impact on SCE's financial
position or results of operations, assuming the remaining book value of the station (approximately $88 million as
of December 31, 2001), and plant closure and decommissioning-related costs are recoverable in future rates.  SCE
cannot predict what effect any future actions by the CPUC may have on this matter.

SCE's projected environmental capital expenditures are $1.3 billion for the 2002-2006 period, mainly for
undergrounding certain transmission and distribution lines.

San Onofre Nuclear Generating Station

In February 2001, SCE's San Onofre Unit 3 experienced a fire due to an electrical fault in the non-nuclear
portion of the plant.  The turbine rotors, bearings and other components of the turbine generator system were
damaged extensively.  In June 2001, Unit 3 returned to service.  Under the currently effective San Onofre
rate-recovery plan (discussed in the Generation and Power Procurement section of Regulatory Environment), SCE's
lost revenue was approximately $98 million as a result of the fire and related outage.



Page 18

------------------------------------------------------------------------------------------------------------------
                                                                                Southern California Edison Company


The San Onofre Units 2 and 3 steam generators' design allows for the removal of up to 10% of the tubes before the
rated capacity of the unit must be reduced.  Increased tube degradation was found during routine inspections in
1997.  To date, 8% of Unit 2's tubes and 6% of Unit 3's tubes have been removed from service.  A decreasing
(favorable) trend in degradation has been observed in more recent inspections.

Critical Accounting Policies

The accounting policies described below are viewed by management as critical because their application is the
most relevant and material to SCE's results of operations and financial position and these policies require the
use of material judgments and estimates.

SCE applies accounting principles for rate-regulated enterprises to the portion of its operations, where
regulators set rates at levels intended to recover the estimated costs of providing service, plus a return on
capital.  Due to timing and other differences in the collection of revenue, these principles allow a cost that
would otherwise be charged to expense by a non-regulated entity to be capitalized as a regulatory asset, if it is
probable that the cost is recoverable through future rates, and conversely allow creation of a regulatory
liability for probable future costs collected through rates in advance.  See further discussion of regulatory
assets and liabilities in Note 1 to the Consolidated Financial Statements.

SCE applied judgment in the use of the above principles when it concluded, as of December 31, 2000, that $4.2
billion of generation-related regulatory assets and liabilities were no longer probable of recovery, and wrote
off these assets as a charge to earnings, and again in fourth quarter 2001 when it created the $3.6 billion
PROACT regulatory asset with a corresponding credit to earnings upon receiving regulatory assurance of collection
of these costs.  See further discussion in Earnings section.

New Accounting Standards

On January 1, 2001, SCE adopted a new accounting standard for derivative instruments and hedging activities.  The
standard requires derivatives to be recognized on the balance sheet at fair value, unless they meet the
definition of a normal purchase or sale.  Gains or losses from changes in the fair value of a recognized asset or
liability or a firm commitment are reflected in earnings for the ineffective portion of the hedge.  For a hedge
of the cash flows of a forecasted transaction, the effective portion of the gain or loss is initially recorded as
a separate component of shareholder's equity under the caption accumulated other comprehensive income, and
subsequently reclassified into earnings when the forecasted transaction affects earnings.  The ineffective
portion of the hedge is reflected in earnings immediately.  SCE does not anticipate any earnings impact from any
derivatives, since it expects that any market price changes will be recovered in rates.  In October 2001,
additional implementation guidance, which will be effective April 1, 2002, was issued.  SCE is still evaluating
the impact of this new implementation guidance.

In July and August 2001, three new accounting standards were issued:  Business Combinations; Goodwill and Other
Intangibles; and Accounting for Asset Retirement Obligations.

The new Business Combinations standard eliminates the pooling-of-interests method, effective June 30, 2001.
After that, all business combinations will be recorded under the purchase method (i.e., record purchase based
upon value exchanged and record goodwill for excess of costs over the net assets acquired).

The new Goodwill and Other Intangibles standard requires that companies cease amortizing goodwill, effective
January 1, 2002.  Goodwill initially recognized after June 30, 2001, will not be amortized.  Goodwill on the
balance sheet at June 30, 2001, was amortized until December 31, 2001.  Under the new standard, goodwill will be
tested for impairment using a fair-value approach when events or circumstances occur indicating that impairment
might exist.  Also, a benchmark assessment for goodwill is required within six months of the date of adoption of
the standard.

The Accounting for Asset Retirement Obligations standard requires entities to record the fair value of a
liability for a legal asset retirement obligation in the period in which it is incurred.  When the liability is

Page 19


-------------------------------------------------------------------------------------------------------------------
Management's Discussion and Analysis of Results of Operations and Financial Condition


initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived
asset.  Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset.  Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss upon settlement.  The standard is
effective for SCE beginning on January 1, 2003.

SCE is studying the impact of the new Asset Retirement Obligations standard and is unable to predict at this time
the effect on its financial statements.  SCE does not anticipate any material impact on its results of operations
or financial position from the other two new accounting standards.

In October 2001, a new accounting standard was issued related to accounting for the impairment or disposal of
long-lived assets.  Although the standard supersedes a prior accounting standard related to the impairment of
long-lived assets, it retains the fundamental provisions of the impairment standard regarding
recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived
assets to be disposed of by sale.  Under the new accounting standard, asset write-downs from discontinuing a
business segment will be treated the same as other assets held for sale.  The new standard also broadens the
financial statement presentation of discontinued operations to include the disposal of an asset group (rather
than a segment of a business).  The standard (effective on January 1, 2002) was adopted early, in fourth quarter
2001.  The adoption of this standard had no effect on SCE's financial statements.

Forward-looking Information

In the preceding Management's Discussion and Analysis of Results of Operations and Financial Condition and
elsewhere in this annual report, the words estimates, expects, anticipates, believes, and other similar
expressions are intended to identify forward-looking information that involves risks and uncertainties.  Actual
results or outcomes could differ materially as a result of important factors that may be outside SCE's control,
including among other things:  the outcome of the pending appeals of the stipulated judgment approving the
settlement agreement with the CPUC, and the effects of other legal actions or ballot initiatives, if any,
attempting to undermine the provisions of the settlement agreement or otherwise adversely affecting SCE; changes
in prices of wholesale electricity and natural gas or in SCE's operating costs, which could cause SCE's cost
recovery to be less than anticipated; the actions of securities rating agencies, including the determination of
whether or when to make changes in SCE's credit ratings, the ability of SCE to regain investment grade ratings,
and the impact of current or lowered ratings and other financial market conditions on the ability of SCE to
obtain needed financing on reasonable terms; further actions by state and federal regulatory bodies setting
rates, adopting or modifying cost recovery, accounting or rate-setting mechanisms and implementing the
restructuring of the electric utility industry, as well as legislative or judicial actions affecting the same
matters; the effects of increased competition in energy-related businesses, including the market entrants and the
effects of new technologies that may be developed in the future; new or increased environmental liabilities; and
weather conditions, natural disasters, and other unforeseen events.





Page 20



-------------------------------------------------------------------------------------------------------------------
Consolidated Statements of Income (Loss)                                        Southern California Edison Company


In millions                    Year ended December 31,                2001              2000               1999
-------------------------------------------------------------------------------------------------------------------
Operating revenue                                                   $ 8,126            $ 7,870           $ 7,548
-------------------------------------------------------------------------------------------------------------------

Fuel                                                                    212                195               215
Purchased power                                                       3,770              4,687             3,190
Provisions for regulatory adjustment clauses - net                   (3,028)             2,301              (763)
Other operation and maintenance                                       1,771              1,772             1,933
Depreciation, decommissioning and amortization                          681              1,473             1,548
Property and other taxes                                                112                126               122
Net gain on sale of utility plant                                        (9)               (25)               (3)
-------------------------------------------------------------------------------------------------------------------

Total operating expenses                                              3,509             10,529             6,242
-------------------------------------------------------------------------------------------------------------------

Operating income (loss)                                               4,617             (2,659)            1,306
Interest and dividend income                                            215                173                69
Other nonoperating income                                                57                118               162
Interest expense - net of amounts capitalized                          (785)              (572)             (483)
Other nonoperating deductions                                           (38)              (110)             (107)
-------------------------------------------------------------------------------------------------------------------

Income (loss) before taxes                                            4,066             (3,050)              947
Income tax (benefit)                                                  1,658             (1,022)              438
-------------------------------------------------------------------------------------------------------------------

Net income (loss)                                                     2,408             (2,028)              509
Dividends on preferred stock                                             22                 22                25
-------------------------------------------------------------------------------------------------------------------

Net income (loss) available for common stock                        $ 2,386           $ (2,050)            $ 484
-------------------------------------------------------------------------------------------------------------------



Consolidated Statements of Comprehensive Income (Loss)


In millions                    Year ended December 31,                2001              2000               1999
-------------------------------------------------------------------------------------------------------------------
Net income (loss)                                                   $ 2,408           $ (2,028)            $ 509
Other comprehensive income, net of tax:
   Unrealized gain on securities - net                                   --                  3                28
   Cumulative effect of change in accounting for derivatives            398                 --                --
   Unrealized loss on cash flow hedges                                 (420)                --                --
   Reclassification adjustment for loss included in net income (loss)    --                (25)              (45)
-------------------------------------------------------------------------------------------------------------------

Comprehensive income (loss)                                         $ 2,386           $ (2,050)            $ 492
-------------------------------------------------------------------------------------------------------------------








                    The accompanying notes are an integral part of these financial statements.
-------------------------------------------------------------------------------------------------------------------


Page 21


Consolidated Balance Sheets


In millions                                          December 31,                      2001                 2000
-------------------------------------------------------------------------------------------------------------------

ASSETS
-------------------------------------------------------------------------------------------------------------------

Cash and equivalents                                                                 $  3,414           $    583
Receivables, less allowances of $32 and $23
   for uncollectible accounts at respective dates                                       1,093                919
Accrued unbilled revenue                                                                  451                377
Fuel inventory                                                                             14                 12
Materials and supplies, at average cost                                                   146                132
Accumulated deferred income taxes - net                                                   433                545
Regulatory assets - net                                                                    83                 --
Prepayments and other current assets                                                      145                124
-------------------------------------------------------------------------------------------------------------------

Total current assets                                                                    5,779              2,692
-------------------------------------------------------------------------------------------------------------------

Nonutility property - less accumulated provision
   for depreciation of $17 and $11 at respective dates                                    159                102
Nuclear decommissioning trusts                                                          2,275              2,505
Other investments                                                                         224                 90
-------------------------------------------------------------------------------------------------------------------

Total investments and other assets                                                      2,658              2,697
-------------------------------------------------------------------------------------------------------------------

Utility plant, at original cost:
   Transmission and distribution                                                       13,568             13,129
   Generation                                                                           1,729              1,745
Accumulated provision for depreciation
   and decommissioning                                                                 (7,969)            (7,834)
Construction work in progress                                                             556                636
Nuclear fuel, at amortized cost                                                           129                143
-------------------------------------------------------------------------------------------------------------------

Total utility plant                                                                     8,013              7,819
-------------------------------------------------------------------------------------------------------------------

Regulatory assets - net                                                                 5,528              2,390
Other deferred charges                                                                    475                368
-------------------------------------------------------------------------------------------------------------------

Total deferred charges                                                                  6,003              2,758
-------------------------------------------------------------------------------------------------------------------






Total assets                                                                         $ 22,453           $ 15,966
-------------------------------------------------------------------------------------------------------------------




                    The accompanying notes are an integral part of these financial statements.


Page 22



-------------------------------------------------------------------------------------------------------------------
                                                                                 Southern California Edison Company

In millions, except share amounts                    December 31,                      2001                2000
-------------------------------------------------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDER'S EQUITY
-------------------------------------------------------------------------------------------------------------------

Short-term debt                                                                      $  2,127           $  1,451
Long-term debt due within one year                                                      1,146                646
Preferred stock to be redeemed within one year                                            105                 --
Accounts payable                                                                        3,261              1,055
Accrued taxes                                                                             823                536
Regulatory liabilities - net                                                               --                195
Other current liabilities                                                               1,645              1,502
-------------------------------------------------------------------------------------------------------------------

Total current liabilities                                                               9,107              5,385
-------------------------------------------------------------------------------------------------------------------

Long-term debt                                                                          4,739              5,631
-------------------------------------------------------------------------------------------------------------------

Accumulated deferred income taxes - net                                                 3,365              2,009
Accumulated deferred investment tax credits                                               153                164
Customer advances and other deferred credits                                              739                722
Power-purchase contracts                                                                  356                467
Accumulated provision for pensions and benefits                                           420                296
Other long-term liabilities                                                               148                127
-------------------------------------------------------------------------------------------------------------------

Total deferred credits and other liabilities                                            5,181              3,785
-------------------------------------------------------------------------------------------------------------------

Commitments and contingencies
   (Notes 3, 11 and 12)

Preferred stock:
   Not subject to mandatory redemption                                                    129                129
   Subject to mandatory redemption                                                        151                256
-------------------------------------------------------------------------------------------------------------------

Total preferred stock                                                                     280                385
-------------------------------------------------------------------------------------------------------------------

   Common stock (434,888,104 shares outstanding
     at each date)                                                                      2,168              2,168
   Additional paid-in capital                                                             336                334
   Accumulated other comprehensive income (loss)                                          (22)                --
   Retained earnings (deficit)                                                            664             (1,722)
-------------------------------------------------------------------------------------------------------------------

Total common shareholder's equity                                                       3,146                780
-------------------------------------------------------------------------------------------------------------------



Total liabilities and shareholder's equity                                           $ 22,453           $ 15,966
-------------------------------------------------------------------------------------------------------------------





                    The accompanying notes are an integral part of these financial statements.


Page 23



------------------------------------------------------------ ---------------------------------------------------------
Consolidated Statements of Cash Flows

In millions                    Year ended December 31,                2001                2000              1999
-------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
Net income (loss)                                                   $ 2,408            $ (2,028)         $   509
Adjustments to reconcile net income (loss) to net cash
  provided by operating activities:
   Depreciation, decommissioning and amortization                       681               1,473            1,548
   Other amortization                                                    82                  97               95
   Deferred income taxes and investment tax credits                   1,313                (928)             178
   Regulatory assets - long-term - net                               (3,135)              1,759           (1,354)
   Gas call options                                                     (91)                 20               11
   Net gain on sale of marketable securities                             --                 (41)             (77)
   Other assets                                                         (68)                 24              (73)
   Other liabilities                                                     17                 (13)              17
   Changes in working capital:
     Receivables and accrued unbilled revenue                          (243)               (282)              99
     Regulatory liabilities - short-term - net                         (278)                 97              363
     Fuel inventory, materials and supplies                             (16)                 29               (5)
     Prepayments and other current assets                               (21)                (14)             (19)
     Accrued interest and taxes                                         365                  48             (186)
     Accounts payable and other current liabilities                   2,251                 588              352
-------------------------------------------------------------------------------------------------------------------

Net cash provided by operating activities                             3,265                 829            1,458
-------------------------------------------------------------------------------------------------------------------

Cash flows from financing activities:
Long-term debt issued                                                    --               1,760              491
Long-term debt repaid                                                    --                (525)            (363)
Bonds repurchased and funds held in trust                              (130)               (440)              --
Rate reduction notes repaid                                            (246)               (246)            (246)
Nuclear fuel financing - net                                            (21)                  9              (37)
Short-term debt financing - net                                         676                 655              326
Dividends paid                                                           (1)               (395)            (686)
-------------------------------------------------------------------------------------------------------------------

Net cash provided (used) by financing activities                        278                 818             (515)
-------------------------------------------------------------------------------------------------------------------

Cash flows from investing activities:
Additions to property and plant                                        (688)             (1,096)            (986)
Funding of nuclear decommissioning trusts                               (36)                (69)            (116)
Proceeds from sales of marketable securities                             --                  41               84
Sales of investments in other assets                                     12                  34               19
-------------------------------------------------------------------------------------------------------------------

Net cash used by investing activities                                  (712)             (1,090)            (999)
-------------------------------------------------------------------------------------------------------------------

Net increase (decrease) in cash and equivalents                       2,831                 557              (56)
Cash and equivalents, beginning of year                                 583                  26               82
-------------------------------------------------------------------------------------------------------------------

Cash and equivalents, end of year                                   $ 3,414               $ 583           $   26
-------------------------------------------------------------------------------------------------------------------

Cash payments for interest and taxes:
Interest - net of amounts capitalized                              $    455               $ 303            $ 287
Tax payments (receipts)                                                (105)                306              433



                    The accompanying notes are an integral part of these financial statements.


Page 24



----------------------------------------------------------------------------- ----------------------------------------
                                                                                      Southern California Edison Company
Consolidated Statements of Changes in Common
Shareholder's Equity

                                                                           Accumulated                    Total
                                                          Additional          Other       Retained       Common
                                              Common        Paid-in       Comprehensive   Earnings    Shareholder's
In millions                                    Stock        Capital       Income (Loss)   (Deficit)      Equity
--------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------

Balance at December 31, 1998                 $ 2,168        $ 334             $ 39      $    794         $ 3,335
--------------------------------------------------------------------------------------------------------------------

Net income                                                                                   509             509
Unrealized gain on securities                                                   46                            46
   Tax effect                                                                  (18)                          (18)
Reclassified adjustment for gain
  included in net income                                                       (77)                          (77)
   Tax effect                                                                   32                            32
Dividends declared on common stock                                                          (666)           (666)
Dividends declared on preferred stock                                                        (25)            (25)
Stock option appreciation                                                                     (3)             (3)
Capital stock expense and other                                 1                             (1)             --
--------------------------------------------------------------------------------------------------------------------

Balance at December 31, 1999                 $ 2,168        $ 335             $ 22      $    608         $ 3,133
--------------------------------------------------------------------------------------------------------------------

Net income (loss)                                                                         (2,028)         (2,028)
Unrealized gain on securities                                                    8                             8
   Tax effect                                                                   (5)                           (5)
Reclassified adjustment for gain
  included in net income                                                       (41)                          (41)
   Tax effect                                                                   16                            16
Dividends declared on common stock                                                          (279)           (279)
Dividends declared on preferred stock                                                        (22)            (22)
Stock option appreciation                                                                     (1)             (1)
Capital stock expense and other                                (1)                                            (1)
--------------------------------------------------------------------------------------------------------------------

Balance at December 31, 2000                 $ 2,168        $ 334              $--      $ (1,722)        $   780
--------------------------------------------------------------------------------------------------------------------

Net income                                                                                 2,408           2,408
Cumulative effect of change in
  accounting for derivatives                                                   398                           398
Unrealized loss on cash flow hedges                                           (420)                         (420)
Dividends accrued on preferred stock                                                         (22)            (22)
Capital stock expense and other                                 2                                              2
-------------------------------------------------------------------------------------------------------------------

Balance at December 31, 2001                 $ 2,168        $ 336            $ (22)     $    664         $ 3,146
--------------------------------------------------------------------------------------------------------------------


Authorized common stock is 560 million shares with no par value.





                    The accompanying notes are an integral part of these financial statements.



Page 25



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


Note 1.  Summary of Significant Accounting Policies

Nature of Operations

Southern California Edison Company (SCE) is a rate-regulated electric utility that supplies electric energy to a
50,000 square-mile area of central, coastal and southern California.

SCE operates in a highly regulated environment and has an exclusive franchise within its service territory.  SCE
has an obligation to deliver electric service to its customers and regulatory authorities have an obligation to
provide just and reasonable rates.  In the mid-1990s, state lawmakers and the California Public Utilities
Commission (CPUC) initiated an electric industry restructuring process.  SCE, as directed by the CPUC, sold its
gas-fired generating stations.  See Note 3 for a further discussion of regulatory changes in the electric utility
industry.

Basis of Presentation

The consolidated financial statements include SCE and its subsidiaries.  Intercompany transactions have been
eliminated.  Certain prior-year amounts were reclassified to conform to the December 31, 2001, financial
statement presentation.

SCE's accounting policies conform to accounting principles generally accepted in the United States, including the
accounting principles for rate-regulated enterprises, which reflect the rate-making policies of the CPUC and the
Federal Energy Regulatory Commission (FERC).  Since 1997, as a result of industry restructuring legislation
enacted by the State of California and related changes in the rate recovery of generation-related assets, SCE has
used accounting principles applicable to enterprises in general for its investment in generation facilities.

Financial statements prepared in compliance with accounting principles generally accepted in the United States
require management to make estimates and assumptions that affect the amounts reported in the financial statements
and disclosure of contingencies.  Actual results could differ from those estimates.  Certain significant
estimates related to regulatory matters, financial instruments, decommissioning and contingencies are further
discussed in Notes 3, 4, 11 and 12 to the Consolidated Financial Statements, respectively.

SCE's outstanding common stock is owned entirely by its parent company, Edison International.

Revenue

Operating revenue includes amounts for services rendered but unbilled at the end of each year.  Since January 17,
2001, power purchased by the California Department of Water Resources (CDWR) or through the Independent System
Operator (ISO) for SCE's customers is not considered a cost to SCE, since SCE is acting as an agent for these
transactions.  Further, amounts billed to ($2.0 billion in 2001) and collected from its customers for these power
purchases are being remitted to the CDWR and are not recognized as revenue to SCE.  See further discussion in
Note 3.

Related Party Transactions

Certain Edison Mission Energy (a wholly owned subsidiary of Edison International) subsidiaries have 49% - 50%
ownership in partnerships (qualifying facilities (QFs)) that sell electricity generated by their project
facilities to SCE under long-term power purchase agreements with terms and pricing approved by the CPUC.  SCE's
purchases from these partnerships were $983 million in 2001, $716 million in 2000 and $513 million in 1999.


Page 26


----------------------------------------------------------------------------------------------------------------
                                                                              Southern California Edison Company

Purchased Power

SCE purchased power through the California Power Exchange (PX) from April 1998 through mid-January 2001.  SCE has
bilateral forward contracts with other entities (as discussed in Note 4) and power-purchase contracts with other
utilities and independent power producers classified as QFs.  Purchased power detail is provided below:

         In millions         Year ended December 31,                 2001             2000           1999
----------------------------------------------------------------------------------------------------------

         PX/ISO:
         Purchases                                               $    775          $ 8,449        $ 2,490
         Generation sales                                             324            6,120          1,719
----------------------------------------------------------------------------------------------------------

         Purchased power - PX/ISO - net                               451            2,329            771
         Purchased power - bilateral contracts                        188               --             --
         Purchased power - interutility/QF contracts                3,131            2,358          2,419
----------------------------------------------------------------------------------------------------------

         Total                                                    $ 3,770          $ 4,687        $ 3,190
----------------------------------------------------------------------------------------------------------


Since January 17, 2001, all other power is purchased by the CDWR for delivery to SCE's customers and is not
considered a cost to SCE.

Planned Major Maintenance

Certain plant facilities require major maintenance on a periodic basis.  All such costs are expensed as incurred.

Other Nonoperating Income and Deductions

Other nonoperating income and deductions was comprised of:

         In millions         Year ended December 31,                 2001             2000           1999
----------------------------------------------------------------------------------------------------------

         Gain on sale of marketable securities                     $   --           $   41         $   77
         AFUDC                                                         16               21             24
         Other                                                         41               56             61
----------------------------------------------------------------------------------------------------------

         Total other nonoperating income                           $   57            $ 118          $ 162
----------------------------------------------------------------------------------------------------------

         Provisions for regulatory issues and refunds              $    7           $   78         $   79
         Other                                                         31               32             28
----------------------------------------------------------------------------------------------------------

         Total other nonoperating deductions                       $   38            $ 110          $ 107
----------------------------------------------------------------------------------------------------------


Cash Equivalents

Cash equivalents include time deposits and other investments with original maturities of three months or less.
All investments are classified as available for sale.

Fuel Inventory

Fuel inventory is valued under the last-in, first-out method for fuel oil and under the first-in, first-out
method for coal.

Investments

Net unrealized gains (losses) on equity investments are recorded as a separate component of shareholder's equity
under the caption "Accumulated other comprehensive income."  Unrealized gains and losses on decommissioning trust
funds are recorded in the accumulated provision for decommissioning.  All investments are classified as
available-for-sale.


Page 27

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Notes to Consolidated Financial Statements


Utility Plant

Utility plant additions, including replacements and betterments, are capitalized.  Such costs include direct
material and labor, construction overhead and an allowance for funds used during construction (AFUDC).  AFUDC
represents the estimated cost of debt and equity funds that finance utility-plant construction.  AFUDC is
capitalized during plant construction and reported in current earnings in other nonoperating  income.  AFUDC is
recovered in rates through depreciation expense over the useful life of the related asset.  Depreciation of
utility plant is computed on a straight-line, remaining-life basis.

AFUDC - equity was $7 million in 2001, $11 million in 2000 and $13 million in 1999.  AFUDC - debt was $9 million
in 2001, $10 million in 2000 and $11 million in 1999.

Replaced or retired property and removal costs less salvage are charged to the accumulated provision for
depreciation.  Depreciation expense stated as a percent of average original cost of depreciable utility plant was
3.6% for 2001, 2000 and 1999.

SCE's net investment in generation-related utility plant was $1.0 billion at both December 31, 2001, and December
31, 2000.

Nuclear

During the second quarter of 1998, SCE reduced its remaining nuclear plant investment by $2.6 billion (book value
as of June 30, 1998) and recorded a regulatory asset on its balance sheet for the same amount in accordance with
asset impairment accounting standards.  For this impairment assessment, the fair value of the investment was
calculated by discounting expected future net cash flows.  The reclassification had no effect on SCE's 1998
results of operations.

SCE had been recovering its investments in San Onofre Nuclear Generating Station Units 2 and 3 and Palo Verde
Nuclear Generating Station on an accelerated basis, as authorized by the CPUC.  The accelerated recovery was to
continue through December 2001, earning a 7.35% fixed rate of return on investment.  San Onofre's operating
costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, were
recovered through an incentive pricing plan that allows SCE to receive about 4 cents per kilowatt-hour through
2003.  Any differences between these costs and the incentive price would flow through to the shareholders.  Palo
Verde's accelerated plant recovery, as well as operating costs, including nuclear fuel and nuclear fuel financing
costs, and incremental capital expenditures, were subject to balancing account treatment through December 31,
2001.  The San Onofre and Palo Verde rate recovery plans and the Palo Verde balancing account were part of the
transition cost balancing account (TCBA).

The nuclear rate-making plans and the TCBA mechanism were to continue for rate-making purposes at least through
2001 for Palo Verde operating costs and through 2003 for the San Onofre incentive pricing plan.  However, due to
the various unresolved regulatory and legislative issues (as discussed in Note 3), as of December 31, 2000, SCE
was no longer able to conclude that the unamortized nuclear investment was probable of recovery through the
rate-making process.  As a result, this balance was written off as a charge to earnings at that time.  Should
SCE's utility-retained generation (URG) application be approved, SCE would reestablish for financial reporting
purposes its unamortized nuclear investment and related flow-through taxes, retroactive to August 31, 2001, based
on a 10-year recovery period, effective January 1, 2001, with a corresponding credit to earnings, and adjust the
PROACT regulatory asset balance to reflect recovery of the nuclear investment in accordance with the final URG
decision.

The benefits of operation of the Palo Verde and San Onofre units were required to be shared equally with
ratepayers beginning in 2002 and 2004, respectively.  In a June 2001 decision, the CPUC granted SCE's request to
eliminate the San Onofre post-2003 benefit sharing mechanism.  The CPUC based its action on compliance with a new
state law.  In a September 2001 decision, the CPUC granted SCE's request to eliminate the Palo Verde post-2001
benefit sharing mechanism and to continue the current rate-making treatment for Palo Verde, including the
continuation of the existing nuclear unit incentive procedure with a

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                                                                                Southern California Edison Company


5 cents per kWh cap on replacement power costs, until resolution of SCE's next general rate case or further CPUC
action.  Palo Verde's existing nuclear unit incentive procedure calculates a reward for performance of any unit
above an 80% capacity factor for a fuel cycle.  See discussion in Note 3 for the proposed and alternate
decisions' impact on the incentive pricing plans.

Regulatory Assets and Liabilities

In accordance with accounting principles for rate-regulated enterprises, SCE records regulatory assets, which
represent probable future revenue associated with certain costs that will be recovered from customers through the
rate-making process, and regulatory liabilities, which represent probable future reductions in revenue associated
with amounts that are to be credited to customers through the rate-making process.

The TCBA was established for the recovery of generation-related transition costs during the four-year rate freeze
period.  The transition revenue account (TRA) was a CPUC-authorized regulatory asset account in which SCE
recorded the difference between revenue received from customers through frozen rates and the costs of providing
service to customers, including power procurement costs.  SCE's discontinuance of accounting principles for
rate-regulated enterprises applicable to its generation assets did not result in a write-off of its
generation-related regulatory assets at that time since the CPUC had approved recovery of these assets through
the TCBA mechanism.

The gains resulting from the sale of 12 of SCE's generating plants during 1998 have been credited to the TCBA.
The coal and hydroelectric generation balancing accounts tracked the differences between market revenue from coal
and hydroelectric generation and the plants' operating costs after April 1, 1998.

On March 27, 2001, the CPUC issued a decision stating, among other things, that the rate freeze had not ended,
and the TCBA mechanism was to remain in place.  However, the decision required SCE to recalculate the TCBA
retroactive to January 1, 1998, the beginning of the rate freeze period.  The new calculation required the coal
and hydroelectric balancing account overcollections (which amounted to $1.5 billion as of December 31, 2000) to
be transferred monthly to the TRA, rather than annually to the TCBA (as previously required).  In addition, it
required the TRA to be transferred to the TCBA on a monthly basis.  Previous rules had called only for
overcollections to be transferred to the TCBA monthly, while undercollections were to remain in the TRA until
they were recovered from future overcollections or the end of the rate freeze, whichever came first.

There are many factors that affect SCE's ability to recover its regulatory assets.  SCE assessed the probability
of recovery of its generation-related regulatory assets in light of the CPUC's March 27, 2001, decisions,
including the retroactive transfer of balances from SCE's TRA to the TCBA and related changes.  These decisions
and other regulatory and legislative actions did not meet SCE's prior expectation that the CPUC would provide
adequate cost recovery mechanisms.  SCE was unable to conclude that its generation-related regulatory assets were
probable of recovery through the rate-making process as of December 31, 2000.  Therefore, in accordance with
accounting rules, SCE recorded a $2.5 billion after-tax charge to earnings at that time, to write off the TCBA
and other regulatory assets.

In addition to the TCBA, generation-related regulatory assets totaling $1.3 billion (including the unamortized
nuclear investment, flow-through taxes, unamortized loss on sale of plant, purchased-power settlements and other
regulatory assets) were written off as of December 31, 2000.

In accordance with an October 2001 settlement agreement between the CPUC and SCE, the CPUC passed a resolution on
January 23, 2002, allowing SCE to establish the procurement-related obligations account (PROACT) regulatory asset
for previously incurred energy procurement costs, retroactive to August 31, 2001. The settlement agreement calls
for the end of the TCBA mechanism as of August 31, 2001, and continuation of the rate freeze (including
surcharges) until the earlier of December 31, 2003, or the date SCE recovers its previously incurred
(undercollected) power procurement costs.  During a period beginning on September 1, 2001, and ending on the
earlier of the date that SCE has recovered all of its procurement-related obligations recorded in the PROACT or
December 31, 2005, SCE will apply to the

Page 29

-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


PROACT the difference between SCE's revenue from retail electric rates (including surcharges) and the costs that
SCE is authorized by the CPUC to recover in retail electric rates.  The balance in the PROACT will accrue
interest.  If SCE has not recovered the entire balance by December 31, 2003, the unrecovered balance will be
amortized for up to an additional two years.

Regulatory assets, less regulatory liabilities, included in the consolidated balance sheets are:

       In millions                           December 31,                         2001             2000
-----------------------------------------------------------------------------------------------------------

       PROACT                                                                   $ 2,641          $     --
       Rate reduction notes - transition cost deferral                            1,453             1,090
       Other:
         Flow-through taxes                                                       1,017               874
         Unamortized loss on reacquired debt                                        254               273
         Environmental remediation                                                   57                52
         Regulatory balancing accounts and other                                    189               (94)
-----------------------------------------------------------------------------------------------------------

       Total                                                                    $ 5,611           $ 2,195
-----------------------------------------------------------------------------------------------------------


The regulatory asset related to the rate reduction notes will be recovered over the terms of those notes.  The
other regulatory assets and liabilities are being recovered through other components of electric rates.

Balancing account undercollections and overcollections accrue interest based on a three-month commercial paper
rate published by the Federal Reserve.  Income tax effects on all balancing account changes are deferred.

New Accounting Standards

On January 1, 2001, SCE adopted a new accounting standard for derivative instruments and hedging activities.
Adoption of this standard had no material impact on SCE's financial statements.  An authoritative accounting
interpretation issued in October 2001 precludes fuel contracts that have variable amounts from qualifying under
the normal purchases and sales exception effective April 1, 2002.  SCE is still evaluating the impact of this new
interpretation.

In July and August 2001, three new accounting standards were issued:  Business Combinations; Goodwill and Other
Intangibles; and Accounting for Asset Retirement Obligations.

The new Business Combinations standard eliminates the pooling-of-interests method, effective June 30, 2001.
After that, all business combinations will be recorded under the purchase method (record goodwill for excess of
costs over the net assets acquired).

The new Goodwill and Other Intangibles standard requires that companies cease amortizing goodwill, effective
January 1, 2002.  Goodwill initially recognized after June 30, 2001, was not amortized.  Goodwill on the balance
sheet at June 30, 2001, was amortized until December 31, 2001.  Under the new standard, goodwill will be tested
for impairment using a fair-value approach when events or circumstances occur indicating that impairment might
exist.  Also, a benchmark assessment for goodwill is required within six months of the date of adoption of the
standard.

The Accounting for Asset Retirement Obligations standard requires entities to record the fair value of a
liability for a legal asset retirement obligation in the period in which it is incurred.  When the liability is
initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived
asset.  Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset.  Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss upon settlement.  The standard is
effective for SCE on January 1, 2003.


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                                                                                Southern California Edison Company


SCE is studying the impact of the new Asset Retirement Obligations standard, and is unable to predict at this
time the effect on its financial statements.  SCE does not anticipate any material impact on its results of
operations or financial position from the Business Combinations and Goodwill and Other Intangibles accounting
standards.

In October 2001, a new accounting standard was issued related to accounting for the impairment or disposal of
long-lived assets.  Although the standard supersedes a prior accounting standard related to the impairment of
long-lived assets, it retains the fundamental provisions of the impairment standard regarding
recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived
assets to be disposed of by sale.  Under the new accounting standard, asset write-downs from discontinuing a
business segment will be treated the same as other assets held for sale.  The new standard also broadens the
financial statement presentation of discontinued operations to include the disposal of an asset group (rather
than a segment of a business).  The standard (effective on January 1, 2002) was adopted early, in fourth quarter
2001.  The adoption of this new standard had no effect on SCE's financial statements.

Note 2.  Liquidity Issues

SCE's liquidity is affected primarily by regulation affecting its ability to recover the cost of power purchases,
debt maturities, access to capital markets, credit ratings, dividend payments and capital expenditures.  Capital
resources include cash from operations and external financings.

Undercollections in the TRA and TCBA mechanisms, coupled with SCE's anticipated near-term capital requirements
and the adverse reaction of the credit markets to continued regulatory uncertainty regarding SCE's ability to
recover its current and future power procurement costs, materially and adversely affected SCE's liquidity
throughout 2001.  As a result of its liquidity concerns, SCE took steps to conserve cash to continue to provide
service to its customers.  As a part of this process, beginning in January 2001, SCE suspended payments owed to
the ISO, the PX and QFs, deferred payments of certain obligations for principal and interest on outstanding debt
and did not declare dividends on any of its cumulative preferred stock.  As applicable, unpaid obligations
continued to accrue interest.  As of March 31, 2001, SCE resumed payment of interest on its debt obligations.
However, since June 30, 2001, SCE deferred the interest payments on its quarterly income debt securities
(subordinated debentures), as allowed by the terms of the securities.  See Note 5.  As long as accumulated
dividends on SCE's preferred stock remained unpaid, SCE could not pay any dividends on its common stock.  Common
stock dividends are additionally restricted as detailed in Note 3.

Based on the rights to cost recovery and revenue established by the settlement agreement with the CPUC and CPUC
implementing orders, including the PROACT resolution, SCE repaid its undisputed past-due obligations on March 1,
2002, with lump-sum payments to creditors from the proceeds of $1.6 billion in senior secured credit facilities,
the remarketing of $196 million in pollution control bonds which were repurchased in late 2000, and existing cash
on hand.  The $1.6 billion senior secured credit facilities consist of a $300 million, two-year revolving credit
loan, a $600 million, one-year loan and a $700 million, three-year loan.  See Note 5.

The proceeds from the senior secured credit facilities and pollution control bond remarketing were used along
with SCE's available cash to repay $3.2 billion in past-due obligations and $1.65 billion in near-term debt
maturities.  The past-due obligations consisted of:  (1) $875 million to the PX; (2) $99 million to the ISO;
(3) $1.1 billion to QFs; (4) $193 million in PX energy credits for energy service providers; (5) $531 million of
matured commercial paper; (6) $400 million of principal on its 5-7/8% and 6-1/2% senior unsecured notes which
were issued prior to the energy crisis; and (7) $23 million in preferred dividends in arrears.  After making
these payments, SCE has no material undisputed obligations that are past due or in default.  The near-term debt
maturities consisted of credit facilities whose maturity dates were extended several times and were scheduled to
mature in March and May 2002.  In addition, SCE has entered into an agreement with the CDWR to pay for prior
deliveries of energy in installments of $100 million on April 1, 2002, $150 million on June 3, 2002, and the
balance on July 1, 2002.


Page 31

-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


SCE's Board of Directors has not declared quarterly common stock dividends to SCE's parent, Edison International,
since September 2000.  Payment of dividends on SCE's common stock is restricted by the settlement agreement
between the CPUC and SCE as detailed in Note 3.

Note 3.  Regulatory Matters

CPUC Litigation Settlement Agreement

In November 2000, SCE filed a lawsuit against the CPUC in federal district court, seeking a ruling that SCE is
entitled to full recovery of its past electricity procurement costs in accordance with the tariffs filed with the
FERC.  By agreement of the parties, a stay of the lawsuit was issued in April 2001 while SCE sought
implementation of legislative, regulatory and executive actions to resolve the California energy crisis and SCE's
related financial and liquidity problems.  In October 2001, the court entered a stipulated judgment approving an
agreement between the CPUC and SCE to settle the pending lawsuit.  On January 23, 2002, the CPUC adopted a
resolution implementing the settlement agreement.

Key elements of the settlement agreement include the following items:

o        Establishment of the PROACT as of September 1, 2001, with an opening balance equal to the amount of
     SCE's procurement-related liabilities as of August 31, 2001 (approximately $6.4 billion), less SCE's cash and
     cash equivalents as of that date (approximately $2.5 billion), and less $300 million.

o        Beginning September 1, 2001, SCE will apply to the PROACT, on a monthly basis, the difference between
     SCE's revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the
     CPUC to recover in retail electric rates.  Unrecovered obligations in the PROACT will accrue interest from
     September 1, 2001.

o        Maintain current rates (including surcharges) in effect until December 31, 2003, subject to certain
     adjustments or, if earlier, until the date that SCE recovers the entire PROACT balance.  If SCE has not
     recovered the entire balance by December 31, 2003, the unrecovered balance will be amortized for up to an
     additional two years.  The parties project that existing retail electric rates, including surcharges and as
     adjusted to reflect certain costs, will likely result in SCE recovering substantially all of its unrecovered
     procurement-related obligations prior to the end of 2003.

o        If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's
     procurement-related obligations, the parties will work together to achieve the securitization.  Proceeds of
     any securitization will be credited to the PROACT when they are actually received.

o        During the period that SCE is recovering its previously incurred procurement-related obligations, no
     penalty will be imposed by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure
     requirements.

o        SCE can incur up to $250 million of recoverable costs to acquire financial instruments and engage in
     other transactions intended to hedge fuel cost risks associated with SCE's retained generation assets and
     power purchase contracts with QFs and other utilities.  As of December 31, 2001, SCE had purchased $209
     million in hedging instruments.

o        SCE will not declare or pay dividends or other distributions on its common stock (all of which is held
     by its parent) prior to the earlier of the date SCE has recovered all of its procurement-related obligations
     in the PROACT or January 1, 2005.  However, if SCE has not recovered all of its procurement-related
     obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common stock dividends,
     and the CPUC will not unreasonably withhold its consent.



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                                                                                Southern California Edison Company


o    To ensure the ability of SCE to continue to provide adequate service, SCE may make capital expenditures above the
     level contained in current rates, up to $900 million per year, which will be treated as recoverable costs.

o    Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General
     to pursue and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses
     to claims arising from any failure to make payments to the PX or ISO, and similar claims by the State of
     California or its agencies against the same adverse parties.  During the recovery period discussed above,
     refunds obtained by SCE related to its procurement-related liabilities will be applied to the balance in the
     PROACT.

The settlement agreement states that one of its purposes is to restore the investment grade creditworthiness of
SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a
state-regulated entity as it has in the past.  SCE cannot provide assurance that it will regain investment grade
credit ratings by any particular date.

On November 28, 2001, a federal court of appeals denied a California consumer group's request for a long-term
stay of the settlement.  The group had alleged that it was denied due process and that the CPUC had no authority
to agree with SCE to violate the statutory rate freeze.  In its ruling, the federal court of appeals also granted
SCE's request for an expedited hearing of the appeal of the settlement filed by the consumer group.  On March 4,
2002, the court of appeals heard argument on the appeal and the matter is now under submission.  A decision could
be issued anytime during the next several months.  SCE cannot predict the outcome of the appeal or the impact
that any outcome would have upon the stipulated judgment or settlement.  Possible outcomes include affirmance, a
return to the district court or reversal of the stipulated judgment.  SCE cannot predict whether or how a ruling
on the stipulated judgment could also affect the settlement agreement.

CDWR Power Purchases

In accordance with an emergency order signed by the governor, the CDWR began making emergency power purchases for
SCE's customers on January 17, 2001.  Amounts SCE bills to and collects from its customers for electric power
purchased and sold by the CDWR and through the ISO are remitted directly to the CDWR and are not recognized as
revenue by SCE.  In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1X) was enacted into law.
AB 1X authorized the CDWR to enter into contracts to purchase electric power and sell power at cost directly to
retail customers being served by SCE, and authorized the CDWR to issue bonds to finance electricity purchases.

On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to the
applicable generation-related retail rate per kWh for electricity (based on rates in effect on January 5, 2001),
for each kWh the CDWR sells to SCE's customers.  The CPUC determined that the generation-related retail rate
should be equal to the total bundled electric rate (including the 1 cent per kWh surcharge adopted by the CPUC on
January 4, 2001) less certain nongeneration-related rates or charges.  For the period January 19 through
January 31, 2001, the CPUC ordered SCE to pay the CDWR at a rate of 6.277 cents per kWh for power delivered to
SCE's customers.  The CPUC determined that the applicable rate component is 7.277 cents per kWh (which increased
to 10.277 cents per kWh for electricity delivered after March 27, 2001, due to the 3 cents surcharge discussed in
Rate Stabilization Proceedings), for electricity delivered by the CDWR to SCE's retail customers after
February 1, 2001, until more specific rates are calculated.  The CPUC ordered SCE to pay the CDWR within 45 days
after the CDWR supplies power to retail customers, subject to penalties for each day the payment is late.

On February 21, 2002, the CPUC issued a decision implementing a CDWR revenue requirement of $9.0 billion to pay
its bonds' costs and energy procurement costs for the period January 17, 2001, through December 31, 2002.  The
decision states that SCE's allocated share of this revenue requirement would be approximately $3.6 billion, and
changes SCE's payment to 9.744 cents per kWh for all bills rendered on or after March 15, 2002.  The decision
requires SCE to pay the CDWR in equal monthly installments over a


Page 33

-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


six-month period the difference in rates between January 17, 2001, and March 15, 2002.  SCE estimates that this
amount is approximately $41 million.

On February 28, 2002, SCE and the CDWR executed an agreement that resolves outstanding issues relating to the
payment for electric power purchased for SCE's customers through the ISO real-time market (known as imbalance
energy).  Under this agreement, SCE will pay the CDWR for imbalance energy previously delivered in three
installments ($100 million on April 1, 2002; $150 million on June 3, 2002; and the balance on July 1, 2002).

Rate Stabilization Proceedings

In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the
four-year rate freeze was to end on March 31, 2002, or earlier, depending on the pace of transition cost
recovery.  In December 2000, SCE filed an amended rate stabilization plan application, stating that the statutory
rate freeze had ended in accordance with California law, and requesting the CPUC to approve an immediate 30%
increase to be effective, subject to refund, January 4, 2001.

In January 2001, independent auditors hired by the CPUC issued a report on the financial condition and solvency
of SCE and its affiliates.  The report confirmed what SCE had previously disclosed to the CPUC in public filings
about SCE's financial condition.  The audit report covered, among other things, cash needs, credit relationships,
accounting mechanisms to track stranded cost recovery, the flow of funds between SCE and Edison International,
and earnings of SCE's California affiliates.  In April 2001, the CPUC adopted an order instituting investigation
that reopens the past CPUC decision authorizing the utilities to form holding companies and initiates an
investigation into: whether the holding companies violated CPUC requirements to give first priority to the
capital needs of their respective utility subsidiaries; whether ring-fencing actions by Edison International and
PG&E Corporation and their respective nonutility affiliates also violated the requirements to give first priority
to the capital needs of their utility subsidiaries; whether the payment of dividends by the utilities violated
requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility
companies; any additional suspected violations of laws or CPUC rules and decisions; and whether additional rules,
conditions, or other changes to the holding company decisions are necessary.  The CPUC ordered testimony and
briefing on these matters, which SCE filed in May and June 2001.  On January 9, 2002, the CPUC issued an interim
decision on the first priority condition.  The decision stated that, at least under certain circumstances, the
condition includes the requirement that holding companies infuse all types of capital into their respective
utility subsidiaries when necessary to fulfill the utility's obligation to serve.  On February 11, 2002, SCE
filed an application for rehearing of the decision stating that the decision is an unlawful and erroneous attempt
to rewrite the first priority condition rather than interpret it and that the decision could result in higher
rates for SCE's customers.  Neither Edison International nor SCE can predict what effects this investigation or
any subsequent actions by the CPUC may have on either one of them.

In March 2001, the CPUC ordered a rate increase in the form of a 3 cents per kWh surcharge applied only to
going-forward electric power procurement costs, effective immediately, and affirmed that a 1 cent interim
surcharge granted in January 2001 is permanent.  The 3 cents surcharge is to be added to the rate paid to the
CDWR.  Although the 3 cents increase was authorized as of March 27, 2001, the surcharge was not collected in
rates until the CPUC established a rate design in early June 2001.  To compensate for the two-month delay in
collecting the 3 cents surcharge, the CPUC authorized an additional1/2cent surcharge for a 12-month period
beginning in June 2001.

Utility-Retained Generation Proceeding

In June 2001, SCE filed a comprehensive proposal for new cost-of-service ratemaking for utility retained
generation through the end of 2002.  After that time, SCE's URG-related revenue requirement will be determined in
the general rate case.  The URG proposal calls for balancing accounts for SCE-owned generation, QF and
interutility contracts, procurement costs and ISO charges based on either actual or CPUC-authorized revenue
requirements.  Under the proposal, the four new balancing accounts would be effective January 1, 2001, for
capital-related costs, and February 1, 2001, for non-capital-related costs.  In

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                                                                                Southern California Edison Company


addition, SCE's unamortized nuclear investment would be amortized and recovered in rates over a 10-year period,
effective January 1, 2001.  Should this application be approved as filed, SCE expects to reestablish for
financial reporting purposes its unamortized nuclear investment and regulatory assets related to purchased-power
settlements and flow-through taxes, with a corresponding credit to earnings, and adjust the PROACT regulatory
asset balance in accordance with the final URG decision.

On January 18, 2002, a CPUC administrative law judge issued a proposed decision and a CPUC commissioner issued an
alternate proposed decision.  Both the proposed and alternate proposed decisions adopt most of the elements of
SCE's application, but propose eliminating an incentive pricing plan for San Onofre, effective January 1, 2002,
and replacing it with balancing account treatment for San Onofre's operating costs, subject to a later
reasonableness review.  On February 7, 2002, another CPUC commissioner issued an alternate proposed decision
recommending continuing the incentive pricing plan for San Onofre Units 2 and 3 through December 31, 2003, as
originally provided in CPUC decisions adopted in early 1996.  A final decision is expected in second quarter 2002.

Wholesale Electricity Markets

In October 2000, SCE filed a joint petition urging the FERC to immediately find the California wholesale
electricity market to be not workably competitive, immediately impose a cap on the price for energy and ancillary
services, and institute further expedited proceedings regarding the market failure, mitigation of market power,
structural solutions and responsibility for refunds.  In December 2000, the FERC took limited action and failed
to impose a price cap.  SCE filed an emergency petition in the federal court of appeals challenging the FERC
order and requesting the FERC to immediately establish cost-based wholesale rates.  The court denied SCE's
petition in January 2001.

In its December 2000 order, the FERC established an "underscheduling" penalty effective January 1, 2001,
applicable to scheduling coordinators that do not schedule sufficient resources to supply 95% of their respective
loads.  In December 2001, the FERC eliminated the underscheduling penalty retroactive to January 1, 2001.

On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy
price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power).  The order
establishes an hourly clearing price based on the costs of the least efficient generating unit during the
period.  Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency periods
and price mitigation in the 11-state western region.  The latest order is in effect until September 30, 2002.

After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25,
2001, the FERC issued an order that limits potential refunds from alleged overcharges to the ISO and PX spot
markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on
daily spot market gas prices.  An administrative law judge will conduct evidentiary hearings on this matter.  SCE
cannot predict the amount of any potential refunds.  Under the settlement of litigation with the CPUC, refunds
will be applied to the balance in the PROACT.

Note 4.  Derivative Instruments and Hedging Activities

SCE's risk management policy allows the use of derivative financial instruments to manage financial exposure on
its investments, fluctuations in interest rates and energy prices, but prohibits the use of these instruments for
speculative or trading purposes.

On January 1, 2001, SCE adopted a new accounting standard for derivative instruments and hedging activities.  The
standard requires derivative instruments to be recognized on the balance sheet at fair value unless they meet the
definition of a normal purchase or sale.  The normal purchases and sales exception requires, among other things,
physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of
business.  Gains or losses from changes in the fair value of a recognized asset or liability or a firm commitment
are reflected in earnings for the ineffective portion of the

Page 35


-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


hedge.  For a hedge of the cash flows of a forecasted transaction, the effective portion of the gain or loss is
initially recorded as a separate component of shareholder's equity under the caption "accumulated other
comprehensive income," and subsequently reclassified into earnings when the forecasted transaction affects
earnings.  The ineffective portion of the hedge is reflected in earnings immediately.

SCE recorded its interest rate swap agreement (terminated January 5, 2001) and its block forward power-purchase
contracts at fair value effective January 1, 2001.  The realized loss of $26 million on the interest rate swap
will be amortized over a period ending in 2008.  Due to downgrades in SCE's credit ratings and SCE's failure to
pay its obligations to the PX, the PX suspended SCE's market trading privileges and sought to liquidate SCE's
remaining block forward contracts.  Before the PX could do so, on February 2, 2001, the state seized the
contracts.  On September 30, 2001, a federal appeals court ruled that the governor of California acted illegally
when he seized the contracts held by SCE.  In conjunction with its settlement agreement with the CPUC, SCE has
agreed to release any claim for compensation against the state for these contracts.  However, if the PX prevails
in its claims against the state, SCE may receive some refunds.

SCE has bilateral forward power contracts, which are considered normal purchases under accounting rules.  SCE is
exposed to credit loss in the event of nonperformance by the counterparties to its bilateral forward contracts,
but does not expect the counterparties to fail to meet their obligations.  The counterparties are required to
post collateral depending on the creditworthiness of each counterparty.

In October and November 2001, SCE purchased $209 million of call options that mitigate its exposure to increases
in natural gas prices.  Amounts paid to QFs for energy are based on natural gas prices.  The options cover
various periods from 2002 through 2003, averaging 11 million MMBtus per month.  Any fair value changes for gas
call options are offset through a regulatory balancing account; therefore, fair value changes do not affect
earnings.

Fair values of financial instruments were:

       In millions                          December 31,               2001                  2000
-----------------------------------------------------------------------------------------------------

       Financial assets:
       Decommissioning trusts                                        $ 2,275               $ 2,505
       Gas options                                                        91                    --

       Financial liabilities:
       DOE decommissioning and
          decontamination fees                                            25                    31
       Interest rate swap                                                 --                    21
       Short-term debt                                                 2,103                 1,339
       Long-term debt                                                  4,659                 5,178
       Preferred stock subject to
          mandatory redemption                                           118                   157
       Preferred stock to be redeemed
          within one year                                                102                    --
-----------------------------------------------------------------------------------------------------


The fair value of financial assets is based on quoted market prices.

Financial liabilities' fair values are based on:  discounted future cash flows for U.S. Department of Energy
(DOE) decommissioning and decontamination fees; quoted market prices for the interest rate swap; and brokers'
quotes for short-term debt, long-term debt and preferred stock.  Due to their short maturities, amounts reported
for cash equivalents approximate fair value.

Note 5.  Long-Term Debt

California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.


Page 36


------------------------------------------------------------------------------------------------------------------
                                                                                Southern California Edison Company


Almost all SCE properties are subject to a trust indenture lien.  SCE has pledged first and refunding mortgage
bonds as security for borrowed funds obtained from pollution control bonds issued by government agencies.  SCE
uses these proceeds to finance construction of pollution control facilities.  Bondholders have limited discretion
in redeeming certain pollution-control bonds, and SCE has arrangements with securities dealers to remarket or
purchase them if necessary.  As a result of investors' concerns regarding SCE's liquidity difficulties and
overall financial condition, SCE had to repurchase $550 million of pollution control bonds in December 2000 and
early 2001 that could not be remarketed in accordance with their terms.  On March 1, 2002, SCE sold approximately
$196 million of the pollution control bonds that SCE had repurchased in late 2000.

Debt premium, discount and issuance expenses are amortized over the life of each issue.  Under CPUC rate-making
procedures, debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if
refinanced, the life of the new debt.

Commercial paper intended to be refinanced for a period exceeding one year, for which SCE has the ability to
refinance, and used to finance nuclear fuel scheduled to be used more than one year after the balance sheet date
is classified as long-term debt.

In December 1997, $2.5 billion of rate reduction notes were issued on behalf of SCE by SCE Funding LLC, a special
purpose entity.  These notes were issued to finance the 10% rate reduction mandated by state law.  The proceeds
of the rate reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable right known as
transition property.  Transition property is a current property right created by the restructuring legislation
and a financing order of the CPUC and consists generally of the right to be paid a specified amount from
non-bypassable rates charged to residential and small commercial customers.  The rate reduction notes are being
repaid over 10 years through these non-bypassable residential and small commercial customer rates which
constitute the transition property purchased by SCE Funding LLC.  The notes are secured by the transition
property and are not secured by, or payable from, assets of SCE or Edison International.  SCE used the proceeds
from the sale of the transition property to retire debt and equity securities.  Although, as required by
accounting principles generally accepted in the United States, SCE Funding LLC is consolidated with SCE and the
rate reduction notes are shown as long-term debt in the consolidated financial statements, SCE Funding LLC is
legally separate from SCE.  The assets of SCE Funding LLC are not available to creditors of SCE or Edison
International and the transition property is legally not an asset of SCE or Edison International.  Due to SCE's
credit downgrade, in January 2001, SCE began remitting its customer collections related to the rate-reduction
notes on a daily basis.

Long-term debt consisted of:

     In millions              December 31,                             2001                    2000
----------------------------------------------------------------------------------------------------------

     First and refunding mortgage bonds:
       2002 - 2026 (5.625% to 7.25%)                                 $ 1,175                 $ 1,175
     Rate reduction notes:
       2002 - 2007 (6.22% to 6.42%)                                    1,478                   1,724
     Pollution-control bonds:
       2008 - 2040 (5.125% to 7.2% and variable)                       1,216                   1,216
     Bonds repurchased                                                  (550)                   (420)
     Funds held by trustees                                              (20)                    (20)
     Debentures and notes:
       2001 - 2029 (5.875% to 7.625% and variable)                     2,450                   2,450
     Subordinated debentures:
       2044 (8.375%)                                                     100                     100
     Commercial paper for nuclear fuel                                    60                      79
     Long-term debt due within one year                               (1,146)                   (646)
     Unamortized debt discount - net                                     (24)                    (27)
----------------------------------------------------------------------------------------------------------

     Total                                                           $ 4,739                 $ 5,631
----------------------------------------------------------------------------------------------------------



Page 37


-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


Long-term debt maturities and sinking-fund requirements for the next five years are:  2002 - $1.1 billion; 2003 -
$1.4 billion; 2004 - $371 million; 2005 - $246 million; and 2006 - $446 million.

As a result of its liquidity concerns, SCE took steps to conserve cash to continue to provide service to its
customers.  As a part of this process, SCE suspended payments of certain obligations, including $400 million of
maturing principal on its 5-7/8% and 6-1/2% senior unsecured notes.  From June 30, 2001, SCE deferred the
interest payments on its quarterly income debt securities (subordinated debentures), as allowed by the terms of
the securities.  All interest in arrears will be paid on April 1, 2002.

On March 1, 2002, SCE closed on $1.6 billion in syndicated senior secured credit facilities providing for $600
million of one-year term loans, $700 million of three-year term loans, and $300 million of two-year revolving
credit loans.  The interest rate for the revolving credit loans and the one-year loan is a eurodollar rate plus
2.5% or a bank prime or equivalent rate plus 1.5%, at SCE's election.  The interest rate for the three-year loans
is a eurodollar rate plus 3% or a bank prime or equivalent rate plus a margin of 2%, at SCE's election.  The
credit facilities are secured by three newly issued series of SCE first mortgage bonds. The proceeds of the
loans, along with available cash, were used to repay all of SCE's past due obligations and near-term maturities,
which include the senior notes.

Note 6.  Short-Term Debt

Short-term debt is used to finance fuel inventories, balancing account undercollections and general cash
requirements, including power purchase payments.  Commercial paper intended to finance nuclear fuel scheduled to
be used more than one year after the balance sheet date is classified as long-term debt in connection with
refinancing terms under five-year term lines of credit with commercial banks.

Short-term debt consisted of:

       In millions            December 31,                                  2001                 2000
-----------------------------------------------------------------------------------------------------------

       Commercial paper                                                   $    531           $    700
       Bank loans                                                            1,650                835
       Other                                                                     6                 --
       Amount reclassified as long-term debt                                   (60)               (79)
       Unamortized discount                                                     --                 (5)
-----------------------------------------------------------------------------------------------------------

       Total                                                               $ 2,127            $ 1,451
-----------------------------------------------------------------------------------------------------------

       Weighted average interest rates                                       5.3%                6.9%


As of January 2001, SCE had borrowed the entire $1.65 billion in funds available under its credit lines.  The
proceeds were used in part to repurchase pollution control bonds; the balance was retained as a liquidity
reserve.  SCE conserved cash by deferring payment of $531 million of matured commercial paper.

SCE repaid its credit line borrowings and commercial paper using proceeds from its March 1, 2002, financings.
See further discussion in Note 2.

Note 7.  Preferred Stock

Authorized shares of preferred and preference stocks are:  $25 cumulative preferred - 24 million; $100 cumulative
preferred - 12 million; and preference - 50 million.  All cumulative preferred stocks are redeemable.
Mandatorily redeemable preferred stocks are subject to sinking-fund provisions.  When preferred shares are
redeemed, the premiums paid are charged to common equity.

Preferred stock redemption requirements for the next five years are:  2002 - $105 million; 2003 - $9 million;
2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.



Page 38


------------------------------------------------------------------------------------------------------------------
                                                                                Southern California Edison Company

Cumulative preferred stocks consisted of:

Dollars in millions, except per share amounts        December 31,                             2001           2000
-------------------------------------------------------------------------------------------------------------------

                                              December 31, 2001
                                       --------------------------------
                                         Shares            Redemption
                                       Outstanding            Price
                                       -----------        -------------

Not subject to mandatory redemption:
$25 par value:
4.08% Series                             1,000,000         $ 25.50                          $  25          $  25
4.24                                     1,200,000           25.80                             30             30
4.32                                     1,653,429           28.75                             41             41
4.78                                     1,296,769           25.80                             33             33
-------------------------------------------------------------------------------------------------------------------
Total                                                                                       $ 129          $ 129
-------------------------------------------------------------------------------------------------------------------

Subject to mandatory redemption:
$100 par value:
6.05% Series                               750,000        $ 100.00                          $  75          $  75
6.45                                     1,000,000          100.00                            100            100
7.23                                       807,000          100.00                             81             81

Preferred stock to be redeemed within one year                                               (105)            --
-------------------------------------------------------------------------------------------------------------------
Total                                                                                       $ 151          $ 256
-------------------------------------------------------------------------------------------------------------------


SCE did not issue or redeem any preferred stock in the last three years.

In 2001, SCE's Board did not declare the regular quarterly dividends for any of SCE's cumulative preferred
stock.  As of February 28, 2002, SCE's preferred stock dividends in arrears were $23 million.  On March 11, 2002,
SCE repaid its past due preferred stock dividends.

Note 8.  Income Taxes

SCE and its subsidiaries are included in Edison International's consolidated federal income tax and combined
state franchise tax returns.  Under an income tax allocation agreement approved by the CPUC, SCE calculates its
tax liability on a stand-alone basis.

Income tax expense includes the current tax liability from operations and the change in deferred income taxes
during the year.  Investment tax credits are amortized over the lives of the related properties.



Page 39


-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


The components of the net accumulated deferred income tax liability were:

     In millions                               December 31,                           2001               2000
----------------------------------------------------------------------------------------------------------------

     Deferred tax assets:
     Decommissioning                                                              $     99          $      98
     Accrued charges                                                                   472                379
     Investment tax credits                                                             72                 81
     Property-related                                                                  192                277
     Regulatory balancing accounts                                                   1,709              1,763
     Unbilled revenue                                                                  (10)               101
     Unrealized gains or losses                                                        310                420
     Other                                                                             145                 56
----------------------------------------------------------------------------------------------------------------
     Total                                                                        $  2,989          $   3,175
----------------------------------------------------------------------------------------------------------------
     Deferred tax liabilities:
     Property-related                                                             $  2,248          $   2,184
     Capitalized software costs                                                        224                264
     Regulatory balancing accounts                                                   2,929              1,632
     Unrealized gains and losses                                                       208                317
     Other                                                                             312                242
----------------------------------------------------------------------------------------------------------------
     Total                                                                        $  5,921          $   4,639
----------------------------------------------------------------------------------------------------------------
     Accumulated deferred income taxes - net                                      $  2,932          $   1,464
----------------------------------------------------------------------------------------------------------------

     Classification of accumulated deferred income taxes:
     Included in deferred credits                                                 $  3,365          $   2,009
     Included in current assets                                                        433                545


The current and deferred components of income tax expense (benefit) were:

     In millions                 Year ended December 31,             2001             2000               1999
----------------------------------------------------------------------------------------------------------------

     Current:
     Federal                                                     $    240         $   (104)            $  299
     State                                                             29               --                 79
----------------------------------------------------------------------------------------------------------------

                                                                      269             (104)               378
----------------------------------------------------------------------------------------------------------------
     Deferred - federal and state:
     Accrued charges                                                  (79)            (133)               (76)
     Investment and energy tax credits - net                           (6)             (41)               (45)
     Property-related                                                 174             (302)              (194)
     Regulatory asset amortization                                   (138)             251                  7
     Regulatory balancing accounts                                  1,345             (740)               371
     State tax - privilege year                                       (36)              31                  7
     Unbilled revenue                                                 101               20                 (5)
     Other                                                             28               (4)                (5)
----------------------------------------------------------------------------------------------------------------

                                                                    1,389             (918)                60
----------------------------------------------------------------------------------------------------------------
     Total                                                       $  1,658         $ (1,022)            $  438
----------------------------------------------------------------------------------------------------------------


The composite federal and state statutory income tax rate was 40.551% for all years presented.



Page 40


------------------------------------------------------------------------------------------------------------------
                                                                                Southern California Edison Company


The federal statutory income tax rate is reconciled to the effective tax rate below:

                                 Year ended December 31,             2001             2000              1999
--------------------------------------------------------------------------------------------------------------
     Federal statutory rate                                          35.0%            35.0%             35.0%
     Capitalized software                                             --               --               (2.4)
     Investment and energy tax credits                               (0.1)             1.4              (4.4)
     Property-related and other                                       0.1             (6.6)              9.3
     State tax - net of federal deduction                             5.8              3.7               8.5
--------------------------------------------------------------------------------------------------------------
     Effective tax rate                                              40.8%            33.5%             46.0%
--------------------------------------------------------------------------------------------------------------


Note 9.  Employee Compensation and Benefit Plans

Employee Savings Plan

SCE has a 401(k) defined-contribution savings plan designed to supplement employees' retirement income.  The plan
received employer contributions of $29 million in 2001, $29 million in 2000 and $25 million in 1999.

Pension Plan

SCE has a noncontributory, defined-benefit pension plan that covers employees meeting minimum
service requirements.  SCE recognizes pension expense as calculated by the actuarial method used for ratemaking.
In April 1999, SCE adopted a cash balance feature for its pension plan.

Information on plan assets and benefit obligations is shown below:

In millions                             Year ended December 31,                        2001              2000
-------------------------------------------------------------------------------------------------------------------

Change in benefit obligation
Benefit obligation at beginning of year                                               $ 2,200          $ 2,075
Service cost                                                                               67               63
Interest cost                                                                             154              155
Actuarial loss (gain)                                                                      88               90
Benefits paid                                                                            (182)            (183)
-------------------------------------------------------------------------------------------------------------------

Benefit obligation at end of year                                                     $ 2,327          $ 2,200
-------------------------------------------------------------------------------------------------------------------

Change in plan assets
Fair value of plan assets at beginning of year                                        $ 3,067          $ 3,078
Actual return on plan assets                                                             (162)             143
Employer contributions                                                                     --               29
Benefits paid                                                                            (182)            (183)
-------------------------------------------------------------------------------------------------------------------

Fair value of plan assets at end of year                                              $ 2,723          $ 3,067
-------------------------------------------------------------------------------------------------------------------

Funded status                                                                        $    396         $    867
Unrecognized net loss (gain)                                                             (234)            (745)
Unrecognized transition obligation                                                         17               22
Unrecognized prior service cost                                                           109              118
-------------------------------------------------------------------------------------------------------------------

Recorded asset                                                                       $    288         $    262
-------------------------------------------------------------------------------------------------------------------

Discount rate                                                                           7.0%             7.25%
Rate of compensation increase                                                           5.0%             5.0%
Expected return on plan assets                                                          8.5%             8.5%



Page 41


-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


Expense components were:

In millions                     Year ended December 31,                2001            2000              1999
-------------------------------------------------------------------------------------------------------------------

Service cost                                                          $   67          $    63           $   66
Interest cost                                                            154              155              146
Expected return on plan assets                                          (251)            (266)            (188)
Special termination benefits                                              13               --               --
Net amortization and deferral                                             (9)             (40)              12
-------------------------------------------------------------------------------------------------------------------
Expense under accounting standards                                       (26)             (88)              36
Regulatory adjustment - deferred                                          39               88               14
-------------------------------------------------------------------------------------------------------------------
Total expense recognized                                              $   13          $    --           $   50
-------------------------------------------------------------------------------------------------------------------


Postretirement Benefits Other Than Pensions

Employees retiring at or after age 55 with at least 10 years of service are eligible for postretirement health
and dental care, life insurance and other benefits.

Information on plan assets and benefit obligations is shown below:

In millions                     Year ended December 31,                                2001              2000
-------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------

Change in benefit obligation
Benefit obligation at beginning of year                                               $ 1,762          $ 1,462
Service cost                                                                               44               39
Interest cost                                                                             129              121
Actuarial loss (gain)                                                                      61              202
Benefits paid                                                                             (71)             (62)
-------------------------------------------------------------------------------------------------------------------

Benefit obligation at end of year                                                     $ 1,925          $ 1,762
-------------------------------------------------------------------------------------------------------------------

Change in plan assets
Fair value of plan assets at beginning of year                                        $ 1,200          $ 1,283
Actual return on plan assets                                                              (92)             (40)
Employer contributions                                                                    102               19
Benefits paid                                                                             (71)             (62)
-------------------------------------------------------------------------------------------------------------------

Fair value of plan assets at end of year                                              $ 1,139          $ 1,200
-------------------------------------------------------------------------------------------------------------------

Funded status                                                                        $   (786)        $   (562)
Unrecognized net loss (gain)                                                              390              141
Unrecognized transition obligation                                                        295              323
-------------------------------------------------------------------------------------------------------------------

Recorded asset (liability)                                                           $   (101)       $     (98)
-------------------------------------------------------------------------------------------------------------------

Discount rate                                                                           7.25%             7.5%
Expected return on plan assets                                                          8.2%              8.2%

Expense components were:

In millions                     Year ended December 31,                2001            2000              1999
-------------------------------------------------------------------------------------------------------------------

Service cost                                                         $    44         $     39          $    46
Interest cost                                                            129              121              109
Expected return on plan assets                                           (98)            (106)             (79)
Special termination benefits                                               2               --               --
Net amortization and deferral                                             27               27               27
-------------------------------------------------------------------------------------------------------------------

Total expense                                                        $   104         $     81          $   103
-------------------------------------------------------------------------------------------------------------------


The assumed rate of future increases in the per-capita cost of health care benefits is 10.5% for 2002, gradually
decreasing to 5.0% for 2008 and beyond.  Increasing the health care cost trend rate by one

Page 42


------------------------------------------------------------------------------------------------------------------
                                                                                Southern California Edison Company


percentage point would increase the accumulated obligation as of December 31, 2001, by $300 million and annual
aggregate service and interest costs by $33 million.  Decreasing the health care cost trend rate by one
percentage point would decrease the accumulated obligation as of December 31, 2001, by $243 million and annual
aggregate service and interest costs by $26 million.

Stock Options and Other Equity-Based Awards

In 1998, Edison International shareholders approved the Edison International equity compensation plan, replacing
the long-term incentive compensation program that had been adopted by Edison International shareholders in 1992.
The 1998 plan authorizes a limited annual award of Edison International common shares and options on shares.  The
annual authorization is cumulative, allowing subsequent issuance of previously unutilized awards.  In May 2000,
the Edison International Board of Directors adopted an additional plan, the 2000 equity plan, under which the
special options discussed below were awarded.

Under the 1992, 1998 and 2000 plans, options on 4.9 million shares of Edison International common stock are
currently outstanding to officers and senior managers.

Each option may be exercised to purchase one share of Edison International common stock, and is exercisable at a
price equivalent to the fair market value of the underlying stock at the date of grant.  Options expire 10 years
after date of grant, and vest over a period of up to five years.

Edison International stock options awarded prior to 2000 include a dividend equivalent feature.  Dividend
equivalents on stock options issued after 1993 and prior to 2000 are accrued to the extent dividends are declared
on Edison International common stock, and are subject to reduction unless certain performance criteria are met.
Only a portion of 1999 Edison International stock option awards include a dividend equivalent feature.

Options issued after 1997 generally have a four-year vesting period.  The special options granted in 2000 vest
over five years, but vesting does not begin until May 2002.  Earlier options had a three-year vesting period with
one-third of the total award vesting annually.  If an option holder retires, dies, is terminated by the company,
or is terminated while permanently and totally disabled (qualifying event) during the vesting period, the
unvested options will vest on a pro rata basis.

Unvested options of any person who has served in the past on the SCE management committee (which was dissolved in
1993) will vest and be exercisable upon a qualifying event.  If a qualifying event occurs, the vested options may
continue to be exercised within their original terms by the recipient or beneficiary except that in the case of
termination by the company where the option holder is not eligible for retirement, vested options are forfeited
unless exercised within one year of termination date.  If an option holder is terminated other than by a
qualifying event, options which had vested as of the prior anniversary date of the grant are forfeited unless
exercised within 180 days of the date of termination.  All unvested options are forfeited on the date of
termination.

The fair value for each option granted, reflecting the basis for the above pro forma disclosures, was determined
on the date of grant using the Black-Scholes option-pricing model.  The following assumptions were used in
determining fair value through the model:

         December 31,                                          2001                        2000
----------------------------------------------------------------------------------------------------------

         Expected life                                   7 years - 10 years           7 years - 10 years
         Risk-free interest rate                            4.7% - 6.1%                  4.7% - 6.0%
         Expected volatility                                 17% - 52%                    17% - 46%
----------------------------------------------------------------------------------------------------------


The application of fair-value accounting to calculate the pro forma disclosures above is not an indication of
future income statement effects.  The pro forma disclosures do not reflect the effect of fair-value accounting on
stock-based compensation awards granted prior to 1995.


Page 43

-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


The weighted-average fair value of options granted during 2001 and 2000 was $4.53 per share option and $5.50 per
share option, respectively.  The weighted-average remaining life of options outstanding as of December 31, 2001,
and December 31, 2000, was 6 years and 7 years, respectively.

For the years after 1999, a portion of the executive long-term incentives was awarded in the form of performance
shares.  The 2000 performance shares were restructured as retention incentives in December 2000, which pay as a
combination of Edison International common stock and cash if the executive remains employed at the end of the
performance period.  The performance period ended December 31, 2001, for half of the award, and ends on
December 31, 2002, for the remainder.  Additional performance shares were awarded in January 2001 and January
2002.  The 2001 performance shares vest December 31, 2003, half in shares of Edison International common stock
and half in cash.  The 2002 performance shares vest December 31, 2004, also half in shares of common stock and
half in cash.  The number of shares that will be paid out from the 2002 performance share awards will depend on
the performance of Edison International common stock relative to the stock performance of a specified group of
peer companies.

The 2000 and 2001 performance shares and deferred stock unit values are accrued ratably over a three-year
performance period.  The 2002 performance shares will be valued based on Edison International's stock performance
relative to the stock performance of other such entities.

In March 2001, deferred stock units were awarded as part of a retention program.  These vest and will be paid
between March 12, 2002, and March 12, 2003, depending on performance.  The deferred stock units are payable on
the vesting date in shares of Edison International common stock.

In October 2001, a stock option retention exchange offer was extended, offering holders of Edison International
stock options granted in 2000 the opportunity to exchange those options for a lesser number of deferred stock
units.  The exchange ratio was based on the Black-Scholes value of the options and the stock price at the time
the offer was extended.  The exchange took place in November 2001; the options that participants elected to
exchange were cancelled, and deferred stock units were issued.  Approximately three options were cancelled for
each deferred stock unit issued.  The deferred stock units will vest 25% per year over four years, with the first
vesting date in November 2002.  The following assumptions were used in determining fair value through the
Black-Scholes option-pricing model:  expected life:  8 - 9 years; risk-free interest rate:  5.10%; expected
volatility:  52%.

SCE measures compensation expense related to stock-based compensation by the intrinsic value method.
Compensation expense recorded under the stock-compensation program was $1 million in 2001, $4 million in 2000 and
$5 million in 1999.

Stock-based compensation expense under the fair-value method of accounting would have resulted in pro forma net
income (loss) available for common stock of $2.383 billion for 2001, $(2.054) billion for 2000 and $484 million
for 1999.

Note 10.  Jointly Owned Utility Projects

SCE owns interests in several generating stations and transmission systems for which each participant provides
its own financing.  SCE's share of expenses for each project is included in the consolidated statements of income.



Page 44


------------------------------------------------------------------------------------------------------------------
                                                                                Southern California Edison Company


The investment in each project as of December 31, 2001, was:

                                                  Investment          Accumulated
                                                      in           Depreciation and        Ownership
         In millions                               Facility          Amortization          Interest
-------------------------------------------------------------------------------------------------------

         Transmission systems:
           Eldorado                              $      41            $     11                60%
           Pacific Intertie                            240                  84                50
         Generating stations:
           Four Corners Units 4 and 5 (coal)           469                 365                48
           Mohave (coal)                               334                 246                56
           Palo Verde (nuclear)(1)                   1,653               1,648                16
           San Onofre (nuclear)(1)                   4,305               4,283                75
-------------------------------------------------------------------------------------------------------

         Total                                   $   7,042            $  6,637
-------------------------------------------------------------------------------------------------------


         (1) Regulatory assets, which were written off as a charge to earnings as of December 31, 2000, as
             discussed in Note 1.

Note 11.  Commitments

Leases

SCE has operating leases, primarily for vehicles, with varying terms, provisions and expiration dates.  Operating
lease expense was $19 million in 2001, $20 million in 2000 and $17 million in 1999.

Estimated remaining commitments for noncancelable leases at December 31, 2001, were:

         Year ended December 31,                                                     In millions
-----------------------------------------------------------------------------------------------------

         2002                                                                            $ 14
         2003                                                                              13
         2004                                                                              11
         2005                                                                               8
         2006                                                                               6
         Thereafter                                                                        13
-----------------------------------------------------------------------------------------------------
         Total                                                                           $ 65
-----------------------------------------------------------------------------------------------------


Nuclear Decommissioning

Decommissioning is estimated to cost $2.1 billion in current-year dollars, based on site-specific studies
performed in 1998 for San Onofre and Palo Verde.  Changes in the estimated costs, timing of decommissioning, or
the assumptions underlying these estimates could cause material revisions to the estimated total cost to
decommission in the near term.  SCE estimates that it will spend approximately $8.6 billion through 2060 to
decommission its nuclear facilities.  This estimate is based on SCE's current dollar decommissioning costs,
escalated at rates ranging from 0.3% to 10.0% (depending on the cost element) annually.  These costs are expected
to be funded from independent decommissioning trusts, which effective June 1999 receive contributions of
approximately $25 million per year.  SCE estimates annual after-tax earnings on the decommissioning funds of 3.9%
to 4.9%.

SCE plans to decommission its nuclear generating facilities by a prompt removal method authorized by the Nuclear
Regulatory Commission.  Decommissioning is expected to begin after the plants' operating licenses expire.  The
operating licenses expire in 2022 for San Onofre Units 2 and 3, and in 2026 and 2028 for the Palo Verde units.
Decommissioning costs, which are recovered through non-bypassable customer rates over the term of each nuclear
facility's operating license, are recorded as a component of depreciation expense.


Page 45

-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


Decommissioning of San Onofre Unit 1 (shut down in 1992 per CPUC agreement) started in 1999 and will continue
through 2008.  All of SCE's San Onofre's Unit 1 decommissioning costs will be paid from its nuclear
decommissioning trust funds.

Decommissioning expense was $96 million in 2001, $106 million in 2000 and $124 million in 1999.  The accumulated
provision for decommissioning, excluding San Onofre Unit 1 and unrealized holding gains, was $1.5 billion at
December 31, 2001, and $1.4 billion at December 31, 2000.  The estimated cost to decommission San Onofre Unit 1
is recorded as a liability.

Decommissioning funds collected in rates are placed in independent trusts, which, together with accumulated
earnings, will be utilized solely for decommissioning.

Trust investments (cost basis) include:

                                                   Maturity
------------------------------------------------------------------------------------------------------------------
     In millions                                     Dates           December 31,       2001               2000
------------------------------------------------------------------------------------------------------------------

     Municipal bonds                              2001 - 2034                        $    463           $   548
     Stocks                                            -                                  637               531
     U.S. government issues                       2001 - 2029                             332               421
     Short-term and other                            2001                                 334               220
------------------------------------------------------------------------------------------------------------------
     Total                                                                           $  1,766           $ 1,720
------------------------------------------------------------------------------------------------------------------


Trust fund earnings (based on specific identification) increase the trust fund balance and the accumulated
provision for decommissioning.  Net earnings were $13 million in 2001, $38 million in 2000 and $58 million in
1999.  Proceeds from sales of securities (which are reinvested) were $3.9 billion in 2001, $4.7 billion in 2000
and $2.6 billion in 1999.  Approximately 91% of the trust fund contributions were tax-deductible.

Other Commitments

SCE has fuel supply contracts which require payment only if the fuel is made available for purchase.  Certain SCE
gas and coal fuel contracts require payment of certain fixed charges whether or not gas or coal is delivered.

SCE has power-purchase contracts with certain QFs (cogenerators and small power producers) and other utilities.
These contracts provide for capacity payments if a facility meets certain performance obligations and energy
payments based on actual power supplied to SCE.  There are no requirements to make debt-service payments.  In an
effort to replace higher-cost contract payments with lower-cost replacement power, SCE has entered into
purchased-power settlements to end its contract obligations with certain QFs.  The settlements are reported as
power purchase contracts on the balance sheets.

SCE has unconditional purchase obligations for part of a power plant's generating output, as well as firm
transmission service from another utility.  Minimum payments are based, in part, on the debt-service requirements
of the provider, whether or not the plant or transmission line is operable.  SCE's minimum commitment under both
contracts is approximately $158 million through 2017.  The purchased-power contract is expected to provide
approximately 5% of current or estimated future operating capacity, and is reported as power purchase contracts
(approximately $31 million).  The transmission service contract requires a minimum payment of approximately
$6 million a year.

Certain commitments for the years 2002 through 2006 are estimated below:

         In millions                                         2002       2003       2004       2005       2006
--------------------------------------------------------------------------------------------------------------

         Fuel supply contract payments                      $ 168      $ 108      $ 103      $ 106      $ 109
         Purchased-power capacity payments                    629        629        626        624        572
--------------------------------------------------------------------------------------------------------------



Page 46


------------------------------------------------------------------------------------------------------------------
                                                                                Southern California Edison Company


Note 12.  Contingencies

In addition to the matters disclosed in these notes, SCE is involved in other legal, tax and regulatory
proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of
business.  SCE believes the outcome of these other proceedings will not materially affect its results of
operations or liquidity.

Energy Crisis Issues

In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International.  As
amended in December 2000 and March 2001, the lawsuit involves securities fraud claims arising from alleged
improper accounting for the TRA undercollections.  The second amended complaint is supposedly filed on behalf of
a class of persons who purchased Edison International common stock between July 21, 2000, and April 17, 2001.
This lawsuit has been consolidated with another similar lawsuit filed on March 15, 2001.  A consolidated class
action complaint was filed on August 3, 2001.  On September 17, 2001, SCE and Edison International filed a motion
to dismiss for failure to state a claim.  On March 8, 2002, the district court issued an order dismissing the
complaint with prejudice.  The plaintiffs could appeal this ruling to the court of appeals.

SCE has been a defendant in a number of legal actions brought by various QFs arising out of SCE's suspension of
payments for electricity delivered by the QFs during the period November 1, 2000, through March 26, 2001.  The QF
claims were eventually largely subsumed within agreements with the litigating QFs providing for a provisional
settlement of the parties' disputes.  On March 1, 2002, SCE paid the amounts due under settlement agreements with
these QFs, which triggered the releases and other provisions of the settlements.  As a result, the litigation
with those QFs to whom payment in full has been made under the parties' settlement agreements should be dismissed
during 2002.  However, SCE's March 1, 2002, payments excluded several QFs or did not result in immediate releases
under the settlement agreements based on unique disputes or other unique circumstances, including the status of
regulatory approval.

Environmental Protection

SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to
operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past
operations on the environment.

SCE records its environmental liabilities when site assessments and/or remedial actions are probable and a range
of reasonably likely cleanup costs can be estimated.  SCE reviews its sites and measures the liability quarterly,
by assessing a range of reasonably likely costs for each identified site using currently available information,
including existing technology, presently enacted laws and regulations, experience gained at similar sites, and
the probable level of involvement and financial condition of other potentially responsible parties.  These
estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site
closure.  Unless there is a probable amount, SCE records the lower end of this reasonably likely range of costs
(classified as other long-term liabilities) at undiscounted amounts.

SCE's recorded estimated minimum liability to remediate its 42 identified sites is $111 million.  The ultimate
costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties
inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable
data for identified sites; the varying costs of alternative cleanup methods; developments resulting from
investigatory studies; the possibility of identifying additional sites; and the time periods over which site
remediation is expected to occur.  SCE believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $279 million.  The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.  SCE has
sold all of its gas-fueled generation plants and has retained some liability associated with the divested
properties.


Page 47

-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $50 million of its
recorded liability, through an incentive mechanism (SCE may request to include additional sites).  Under this
mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%,
with the opportunity to recover these costs from insurance carriers and other third parties.  SCE has
successfully settled insurance claims with all responsible carriers.  Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates.  SCE has recorded a regulatory asset of $76 million for its
estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

SCE's identified sites include several sites for which there is a lack of currently available information,
including the nature and magnitude of contamination, and the extent, if any, that SCE may be held responsible for
contributing to any costs incurred for remediating these sites.  Thus, no reasonable estimate of cleanup costs
can now be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years.  Remediation costs in each of the
next several years are expected to range from $10 million to $25 million.  Recorded costs for 2001 were
$18 million.

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the
upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental-cleanup
costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or
financial position.  There can be no assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will not require material revisions to such
estimates.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $9.5 billion.  SCE and other owners of San
Onofre and Palo Verde have purchased the maximum private primary insurance available ($200 million).  The balance
is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor
licensee if a nuclear incident at any licensed reactor in the U.S. results in claims and/or costs which exceed
the primary insurance at that plant site.  Federal regulations require this secondary level of financial
protection.  The Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective
June 1994.  The maximum deferred premium for each nuclear incident is $88 million per reactor, but not more than
$10 million per reactor may be charged in any one year for each incident.  Based on its ownership interests, SCE
could be required to pay a maximum of $175 million per nuclear incident.  However, it would have to pay no more
than $20 million per incident in any one year.  Such amounts include a 5% surcharge if additional funds are
needed to satisfy public liability claims and are subject to adjustment for inflation.  If the public liability
limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims,
including a possible additional assessment on all licensed reactor operators.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and
Palo Verde.  Decontamination liability and property damage coverage exceeding the primary $500 million also has
been purchased in amounts greater than federal requirements.  Additional insurance covers part of replacement
power expenses during an accident-related nuclear unit outage.  These policies are issued by a mutual insurance
company owned by utilities with nuclear facilities.  If losses at any nuclear facility covered by the arrangement
were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium
adjustments of up to $35 million per year.  Insurance premiums are charged to operating expense.

Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and development of a facility for disposal of spent
nuclear fuel and high-level radioactive waste.  Such a facility was to be in operation by January 1998.  However,
the DOE did not meet its obligation.  It is not certain when the DOE will begin

Page 48


------------------------------------------------------------------------------------------------------------------
                                                                                Southern California Edison Company


accepting spent nuclear fuel from San Onofre or from other nuclear power plants.  Extended delays by the DOE
could lead to consideration of costly alternatives involving siting and environmental issues.  SCE has paid the
DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983 (approximately
$24 million, plus interest).  SCE is also paying the required quarterly fee equal to one mill per kilowatt-hour
of nuclear-generated electricity sold after April 6, 1983.

SCE, as operating agent, has primary responsibility for the interim storage of its spent nuclear fuel at San
Onofre.  Current capability to store spent fuel is estimated to be adequate through 2005.  SCE plans to spend
approximately $34 million for the initial interim spent fuel storage at San Onofre Units 2 and 3 through 2008.

Palo Verde on-site spent fuel storage capacity will accommodate needs until 2003 for Unit 2, and until 2004 for
Units 1 and 3.  Arizona Public Service Company, operating agent for Palo Verde, is constructing an interim fuel
storage facility that is expected to be completed in 2002.


-------------------------------------------------------------------------------------------------------------------
Quarterly Financial Data
                                                 2001                                        2000
                            -------------------------------------------    ---------------------------------------
In millions                 Total    Fourth    Third    Second     First  Total   Fourth    Third   Second   First
-------------------------------------------------------------------------------------------------------------------

Operating revenue          $8,126    $2,296   $2,726    $1,592   $1,512   $7,870  $1,755   $2,432   $1,853  $1,830
Operating income (loss)     4,617     3,956    1,294       204     (837)  (2,659) (3,840)     447      385     349
Net income (loss)           2,408     2,310      657        34     (593)  (2,028) (2,485)     177      161     119
Net income (loss) available for
  common stock              2,386     2,304      652        28     (598)  (2,050) (2,491)     172      156     113
Common dividends declared      --        --       --        --       --      279      --       92       91      96
-------------------------------------------------------------------------------------------------------------------





Page 49



-------------------------------------------------------------------------------------------------------------------
Responsibility for Financial Reporting                                          Southern California Edison Company



The management of Southern California Edison Company (SCE) is responsible for the integrity and objectivity of
the accompanying financial statements.  The statements have been prepared in accordance with accounting
principles generally accepted in the United States and are based, in part, on management estimates and judgment.

SCE maintains systems of internal control to provide reasonable, but not absolute, assurance that assets are
safeguarded, transactions are executed in accordance with management's authorization and the accounting records
may be relied upon for the preparation of the financial statements.  There are limits inherent in all systems of
internal control, the design of which involves management's judgment and the recognition that the costs of such
systems should not exceed the benefits to be derived.  SCE believes its systems of internal control achieve this
appropriate balance.  These systems are augmented by internal audit programs through which the adequacy and
effectiveness of internal controls and policies and procedures are monitored, evaluated and reported to
management.  Actions are taken to correct deficiencies as they are identified.

SCE's independent public accountants, Arthur Andersen LLP, are engaged to audit the financial statements in
accordance with auditing standards generally accepted in the United States and to express an informed opinion on
the fairness, in all material respects, of SCE's reported results of operations, cash flows and financial
position.

As a further measure to assure the ongoing objectivity of financial information, the audit committee of the board
of directors, which is composed of outside directors, meets periodically, both jointly and separately, with
management, the independent public accountants and internal auditors, who have unrestricted access to the
committee.  The committee recommends annually to the board of directors the appointment of a firm of independent
public accountants to conduct audits of SCE's financial statements; considers the independence of such firm and
the overall adequacy of the audit scope and SCE's systems of internal control; reviews financial reporting
issues; and is advised of management's actions regarding financial reporting and internal control matters.

SCE maintains high standards in selecting, training and developing personnel to assure that its operations are
conducted in conformity with applicable laws and is committed to maintaining the highest standards of personal
and corporate conduct.  Management maintains programs to encourage and assess compliance with these standards.






Thomas M. Noonan                                                       Alan J. Fohrer
Thomas M. Noonan                                                       Alan J. Fohrer
Vice President                                                         Chairman of the Board
and Controller                                                         and Chief Executive Officer


March 25, 2002




Page 50



-------------------------------------------------------------------------------------------------------------------
Report of Independent Public Accountants                                        Southern California Edison Company



To Southern California Edison Company:

We have audited the accompanying consolidated balance sheets of Southern California Edison Company (SCE, a
California corporation) and its subsidiaries as of December 31, 2001, and 2000, and the related consolidated
statements of income (loss), comprehensive income (loss), cash flows and changes in common shareholder's equity
for each of the three years in the period ended December 31, 2001.  These financial statements are the
responsibility of SCE's management.  Our responsibility is to express an opinion on these financial statements
based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States.  Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial
statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the
financial position of SCE and its subsidiaries as of December 31, 2001, and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States.





                                                                       ARTHUR ANDERSEN LLP
                                                                       ARTHUR ANDERSEN LLP


Los Angeles, California
March 25, 2002



Page 51





-------------------------------------------------------------------------------------------------------------------
Board of Directors                                                              Southern California Edison Company
-------------------------------------------------------------------------------------------------------------------



Page


Warren Christopher*
Senior Partner,
O'Melveny & Myers (law firm),
Los Angeles, California

Alan J. Fohrer
Chairman of the Board and
Chief Executive Officer,
Southern California Edison Company

Joan C. Hanley
The Former General Partner and Manager,
Miramonte Vineyards,
Rancho Palos Verdes, California



*  Retiring on May 14, 2002.

Carl F. Huntsinger*
General Partner,
DAE Limited Partnership Ltd.
(agricultural management),
Ojai, California

Charles D. Miller*
Retired Chairman of the Board,
Avery Dennison Corporation (manu-facturer of self-adhesive products),
Pasadena, California

Luis G. Nogales
Managing Partner,
Nogales Investors (a private equity
investment company),
Los Angeles, California

Ronald L. Olson
Senior Partner,
Munger, Tolles and Olson (law firm),
Los Angeles, California

James M. Rosser
President,
California State University, Los Angeles,
Los Angeles, California

Robert H. Smith
Managing Director,
Smith and Crowley Inc.
(merchant banking),
Pasadena, California

Thomas C. Sutton
Chairman of the Board and
Chief Executive Officer
Pacific Life Insurance Company,
Newport Beach, California

Daniel M. Tellep
Retired Chairman of the Board,
Lockheed Martin Corporation
(aerospace industry),
Bethesda, Maryland


-------------------------------------------------------------------------------------------------------------------
Management Team
-------------------------------------------------------------------------------------------------------------------


Alan J. Fohrer
Chairman of the Board and
Chief Executive Officer

Robert G. Foster
President

Harold B. Ray
Executive Vice President,
Generation Business Unit

Pamela A. Bass
Senior Vice President,
Customer Service Business Unit

John R. Fielder
Senior Vice President,
Regulatory Policy and Affairs

Stephen E. Pickett
Senior Vice President and
General Counsel

Richard M. Rosenblum
Senior Vice President,
Transmission and Distribution
Business Unit

Mahvash Yazdi
Senior Vice President and
Chief Information Officer

Emiko Banfield
Vice President, Shared Services

Robert C. Boada
Vice President and Treasurer

Clarence Brown
Vice President,
Corporate Communications

Bruce C. Foster
Vice President, San Francisco Regulatory Operations

A. L. Grant
Vice President, Engineering and
Technical Services

Frederick J. Grigsby, Jr.
Vice President, Human Resources and Labor Relations

Lawrence D. Hamlin
Vice President, Power Production

Harry B. Hutchison
Vice President, Mass Customers

James A. Kelly
Vice President,
Regulatory Compliance

Russell W. Krieger
Vice President,
Nuclear Generation

Thomas M. Noonan
Vice President and Controller

Dwight E. Nunn
Vice President, Nuclear Engineering
and Technical Services

Pedro J. Pizarro
Vice President,
Business Development

Frank J. Quevedo
Vice President, Equal Opportunity

W. James Scilacci
Vice President and
Chief Financial Officer

Dale E. Shull, Jr.
Vice President, Power Delivery

Anthony L. Smith
Vice President, Tax

Joseph J. Wambold
Vice President, Nuclear Business and Support Services

Beverly P. Ryder
Secretary


Page 52





Shareholder Information
-------------------------------------------------------------------------------------------------------------------

Annual Meeting of Shareholders

Tuesday, May 14, 2002
10:00 a.m.
DoubleTree Hotel Ontario
222 N. Vineyard Avenue
Ontario, California 91764

-------------------------------------------------------------------------------------------------------------------

Stock Listing and Trading Information

SCE Preferred Stock

SCE's preferred stocks are listed on the American and Pacific stock exchanges under the ticker symbol SCE.
Previous day's closing prices, when traded, are listed in the daily newspapers in the American Stock Exchange
composite table.  The 6.05%, 6.45% and 7.23% series are not listed.

Where to Buy and Sell Stock

The listed preferred stocks may be purchased through any brokerage firm.  Firms handling unlisted series can be
located through your broker.

-------------------------------------------------------------------------------------------------------------------

Transfer Agent and Registrar

Wells Fargo Bank Minnesota, N.A. maintains shareholder records and is the transfer agent and registrar for SCE
preferred stock.  Shareholders may call Wells Fargo Shareowner Services, (800) 347-8625, between 7:00 a.m. and
7:00 p.m. (Central Time), Monday through Friday, regarding:

o        stock transfer and name-change requirements;
o        address changes, including dividend addresses;
o        electronic deposit of dividends;
o        taxpayer identification number submission or changes;
o        duplicate 1099 forms and W-9 forms;
o        notices of, and replacement of, lost or destroyed stock certificates and dividend checks; and
o        requests for access to online account information.

The address of Wells Fargo Shareowner Services is:

161 North Concord Exchange Street
South St. Paul, MN 55075-1139
FAX: (651) 450-4033
E-mail:  stocktransfer@wellsfargo.com
         ----------------------------




SCE Web Address:
www.edisoninvestor.com















Southern California Edison Company
2244 Walnut Grove Avenue
Rosemead, California 91770
(626) 302-1212